Edgar Filing: EL PASO ELECTRIC CO /TX/

Since 1999
(a)

Authorized
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Shares repurchased (b)

Cost, including commission (in thousands)

Total remaining shares available for repurchase at December 31, 2013

2013 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

Form 10-K

(Mark One)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-14206

El Paso Electric Company

(Exact name of registrant as specified in its charter)



Texas		74-0607870
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Stanton Tower, 100 North Stanton, El Paso, Texas		79901
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (915) 543-5711

Securities Registered Pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Stock, No Par Value		New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

YES x NO ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

YES ¨ NO x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 126-2 of the Exchange Act.



Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ¨ NO x

As of June 30, 2013, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,401,286,283 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2014, there were 40,279,810 shares of the Company’s no par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for the 2014 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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DEFINITIONS

The following abbreviations, acronyms or defined terms used in this report are defined below:



Abbreviations, Acronyms or Defined Terms		Terms

ANPP Participation Agreement		Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
APS		Arizona Public Service Company
ASU		Accounting Standards Update
Company		El Paso Electric Company
DOE		United States Department of Energy
El Paso		City of El Paso, Texas
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fort Bliss		Fort Bliss the United States Army post next to El Paso, Texas
Four Corners		Four Corners Generating Station
kV		Kilovolt(s)
kW		Kilowatt(s)
kWh		Kilowatt-hour(s)
Las Cruces		City of Las Cruces, New Mexico
MW		Megawatt(s)
MWh		Megawatt-hour(s)
NERC		North American Electric Reliability Corporation
NMPRC		New Mexico Public Regulation Commission
Net dependable generating capability		The maximum load net of plant operating requirements which a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
NRC		Nuclear Regulatory Commission
Palo Verde		Palo Verde Nuclear Generating Station
Palo Verde Participants		Those utilities who share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM		Public Service Company of New Mexico
PUCT		Public Utility Commission of Texas
RGEC		Rio Grande Electric Cooperative
RGRT		Rio Grande Resources Trust
TEP		Tucson Electric Power Company



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TABLE OF CONTENTS




Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	16
1B	Unresolved Staff Comments	21
2	Properties	21
3	Legal Proceedings	21
4	Mine Safety Disclosures	21


	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
6	Selected Financial Data	25
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
7A	Quantitative and Qualitative Disclosures About Market Risk	42
8	Financial Statements and Supplementary Data	44
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	97
9A	Controls and Procedures	97
9B	Other Information	97

	PART III
10	Directors, Executive Officers and Corporate Governance	98
11	Executive Compensation	98
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	98
13	Certain Relationships and Related Transactions, and Director Independence	98
14	Principal Accounting Fees and Services	98

	PART IV
15	Exhibits and Financial Statement Schedules	99



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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K other than statements of historical information are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe", "anticipate", "target", "expect", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning and include, but are not limited to, such things as:


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations, and


•	the overall economy of our service area.

These forward-looking statements involve known and unknown risks that may cause our actual results in future periods to differ materially from those expressed in any forward-looking statement. Factors that would cause or contribute to such differences include, but are not limited to, such things as:


•	our ability to recover our costs and earn a reasonable rate of return on our invested capital through the rates that we charge,


•	the ability of our operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde and Four Corners plants, including costs to comply with any potential new or expanded regulatory or environmental requirements,


•	reductions in output at generation plants operated by us,


•	unscheduled outages of generating units including outages at Palo Verde,


•	the size of our construction program and our ability to complete construction on budget,


•	potential delays in our construction schedule due to legal or other reasons,


•	disruptions in our transmission system, and in particular the lines that deliver power from our remote generating facilities,


•	electric utility deregulation or re-regulation,


•	regulated and competitive markets,


•	ongoing municipal, state and federal activities,


•	economic and capital market conditions,


•	changes in accounting requirements and other accounting matters,


•	changing weather trends and the impact of severe weather conditions,


•	rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on a timely basis,


•	changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas emissions or other environmental matters,



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•	changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies,


•	cuts in military spending or shutdowns of the federal government that reduce demand for our services from military and governmental customers,


•	political, legislative, judicial and regulatory developments,


•	the impact of lawsuits filed against us,


•	the impact of changes in interest rates,


•	changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other post-retirement plan assets,


•	the impact of recent U.S. health care reform legislation,


•	the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde,


•	Texas, New Mexico and electric industry utility service reliability standards,


•	homeland security considerations, including those associated with the U.S./Mexico border region,


•	coal, uranium, natural gas, oil and wholesale electricity prices and availability,


•	possible income tax and interest payments as a result of audit adjustments proposed by the IRS or state taxing authorities, and


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis" "–Summary of Critical Accounting Policies and Estimates" and "–Liquidity and Capital Resources." This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.



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PART I


Item 1.	Business

General

El Paso Electric Company (the "Company") is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in several electrical generating facilities providing it with a net dependable generating capability of approximately 1,852 MW. For the year ended December 31, 2013, the Company’s energy sources consisted of approximately 46% nuclear fuel, 34% natural gas, 6% coal, 14% purchased power and less than 1% generated by Company-owned solar photovoltaic panels and wind turbines. The Company's current generation portfolio exhibits lower carbon intensity than any other utility in the southwestern United States and the Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2013, the Company has power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources- Purchased Power").

The Company serves approximately 394,000 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 62% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2013). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, including Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico, an oil refinery, two large universities, several medical centers and a steel production facility.

The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2014, the Company had approximately 1,000 employees, 38% of whom are covered by a collective bargaining agreement.

The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the Company's website is not incorporated into this document by reference.

Facilities

As of December 31, 2013, the Company’s net dependable generating capability of 1,852 MW consists of the following:



Station	Primary Fuel Type	Company's Share of Net Dependable Generating Capability * (MW)	Company Ownership Interest		Location
Palo Verde Station	Nuclear	633	15.8	%	Wintersburg, Arizona
Newman Power Station	Natural Gas	732	100	%	El Paso, Texas
Rio Grande Power Station	Natural Gas	316	100	%	Sunland Park, New Mexico
Four Corners Station (Units 4 and 5)	Coal	108	7	%	Fruitland, New Mexico
Copper Power Station	Natural Gas	62	100	%	El Paso, Texas
Renewables	Wind/Solar	1	100	%	Hudspeth/El Paso Counties, Texas
Total		1,852

____________________

* During summer peak period. Company owned renewables include a wind ranch with a total capacity of 1.32 MW and six solar photovoltaic facilities with a total capacity of 0.2 MW.

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Palo Verde Station

The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde.


•	License Extension. In 2011, the NRC renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively.

•

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. In 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"), which estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs. At December 31, 2013, the Company's decommissioning trust fund had a balance of $214.1 million. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change.

•

Spent Fuel Storage. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE's breach of the spent nuclear fuel contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.0 million in damages to the Palo Verde participants for costs incurred through December 2006. In October 2010, the Company received $4.8 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.The lawsuit is presently pending in the Court of Federal Claims.

The DOE had planned to meet its disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the D.C. Circuit. In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds. The Company cannot predict when spent fuel shipments to the DOE will commence.

APS and the Company believe that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the current term of its operating license. The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde which the Company believes are the responsibility of the DOE. These costs are assigned to fuel requiring the additional on-site storage and amortized as that fuel is burned until an agreement is reached with the DOE for recovery of these costs.

•

NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation.

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The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, the Company cannot predict the ultimate financial or operational impacts on Palo Verde or the Company; however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (the Company's share is $15.8 million).

•

Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $60.4 million, with an annual payment limitation of approximately $9 million. The Palo Verde Participants also maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.

Fossil-Fueled Plants

The Newman Power Station consists of three steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.

The Company's Rio Grande Power Station consists of three steam-electric generating units and one aeroderivative unit which operate on natural gas.

The Company owns a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. Four Corners is located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016. APS, on behalf of the Four Corners participants, negotiated amendments to the lease with the Navajo Nation which extended the lease from 2016 to 2041, pending the approval of the Department of the Interior and a Federal environmental review.

The 50-year participation agreement among the owners of Four Corners expires by its terms in July 2016. The Company has notified the other owners that it has decided to cease its participation in the plant by July 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation. The Company has nevertheless agreed to work with the other owners and the Navajo Nation in an attempt to facilitate their efforts to extend the operation of the plant beyond July 2016 in a manner consistent with protecting the Company's ratepayers. In December 2013, the other owners executed a long-term extension of the coal supply agreement for the plant through 2031. The Company did not sign the extension and APS has agreed to assume the resulting 7% shortfall and has also expressed an interest in acquiring the Company’s interest in Four Corners.

The Company's Copper Power Station consists of a combustion turbine used primarily to meet peak demand.

Wind and Solar Photovoltaic Facilities

The Company’s Hueco Mountain Wind Ranch consists of two wind turbines with a total capacity of 1.32 MW. The Company also owns six solar photovoltaic facilities with a total capacity of 0.2 MW

Transmission and Distribution Lines and Agreements

The Company owns or has significant ownership interests in four 345 kV transmission lines in New Mexico, three 500 kV lines in Arizona, and owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.

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In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:



Line	Length (miles)	Voltage (kV)	Company Ownership Interest
Springerville-Macho Springs-Luna-Diablo Line (1)	310	345	100.0	%
West Mesa-Arroyo Line (2)	202	345	100.0	%
Greenlee-Hidalgo-Luna-Newman Line (3)
Greenlee-Hidalgo	60	345	40.0	%
Hidalgo-Luna	50	345	57.2	%
Luna-Newman	86	345	100.0	%
Eddy County-AMRAD Line (4)	125	345	66.7	%
Palo Verde Transmission
Palo Verde-Westwing (5)	45	500	18.7	%
Palo Verde-Jojoba-Kyrene (6)	75	500	18.7	%

____________________


(1)	Runs from TEP's Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.


(2)	Runs from PNM's West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico.


(3)	Runs from TEP's Greenlee Substation near Duncan, Arizona to the Newman Power Station.

(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico. Due to damage caused by severe weather conditions which occurred in November and December of 2013, this transmission line is not currently in service. The Company cannot currently predict when this line will return to service.


(5)	Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.

(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona.

Environmental Matters

General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.

Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the Company's operations, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.

Clean Air Interstate Rule/Cross State Air Pollution Rule. The U.S. Environmental Protection Agency's (the "EPA") Clean Air Interstate Rule ("CAIR"), as applied to the Company since 2009, involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, on appeal the rule was reinstated until such time as the EPA promulgates a replacement rule. Because the appellate court in August 2012 also vacated the EPA’s proposed replacement, which is called the Cross-State Air Pollution Rule ("CSAPR"), CAIR remains in effect. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit's decision to vacate CSAPR. On June 24, 2013,

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the Supreme Court agreed to hear the case, and oral arguments were heard on December 10, 2013. The timing and outcome of the Supreme Court decision is unknown, and in the meantime, the Company remains subject to CAIR.

National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both NOx and SO2. In December 2012, the EPA tightened the NAAQS for fine PM, and it is expected to propose more stringent ozone NAAQS in 2014 (with a final rule in 2015). The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and financial results.

Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several judicial and other challenges are being made to this rule. These challenges notwithstanding, companies impacted by the new standards will generally have up to three years to comply. Information from the Four Corners plant operator, APS, indicates that APS currently believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards.

Other Laws and Regulations and Risks. As stated above, the Company intends to cease its participation in Four Corners at the expiration of the 50-year participation agreement in 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation, which is subject to extensive regulation and litigation. For example, as a result of APS’s recent Best Available Retrofit Technology Federal Implementation Plan compliance strategy notification to the EPA, Four Corners is required to install expensive pollution control equipment in order to continue operation in the future. The Company’s share of the cost of these controls is currently estimated by APS to be approximately $39 million if the Company were to extend its participation in the plant. In addition, the EPA has entered into a consent decree which would require it to sign for publication a final action regarding the regulation of coal combustion residuals ("CCR") under the federal Resource, Conservation and Recovery Act by December 19, 2014. Once issued, the Company may be required to incur significant costs to address CCRs either generated in the past and disposed of at or from Four Corners, as well as CCRs generated in connection with the ongoing operations of Four Corners. Further, assured supplies of water are important for the Company's operations and assets, including Four Corners. Four Corners is located in a region that has been experiencing drought conditions which could affect the plant’s water supply. Four Corners has accordingly been involved in negotiations and proceedings with third parties relating to water supply issues. The drought conditions and related negotiations and proceedings could adversely affect the amount of power available, or the price thereof, from Four Corners.

Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting greenhouse gas ("GHG") emissions, including carbon dioxide. In particular, the U.S. Congress periodically considers legislation to restrict or regulate GHG emissions. In the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which applied to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions, which may create significant costs for power plant owners and operators. On June 25, 2013, President Obama set forth his plan to address climate change. He reiterated a goal of reducing GHG "in the range of 17 percent" below 2005 levels by 2020. The plan included a variety of executive actions, including future regulatory measures to reduce carbon emissions from power plants. In a White House memorandum of the same date, the President directed the EPA to issue a new proposal for GHG rulemaking addressing new power plants by September 20, 2013, and a rule for existing power plants by June 1, 2014. The formal proposal for new power plants was published in the Federal Register on January 8, 2014. The Company continues its review of the new proposal and plans to participate in the 60-day post-publication comment period. Given the very significant remaining uncertainties regarding these rules, the Company believes it is impossible to meaningfully quantify the costs of these potential requirements at present.

In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or

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require the Company to purchase rights to emit GHGs, any of which could be material to the Company's business, financial condition, reputation or results of operations.

Climate change also has potential physical effects that could be relevant to the Company's business. In particular, some studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present.

Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters related to Four Corners. In particular, since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going and the Company is unable to predict the outcome of these settlement negotiations.

The Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPS program. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners' participants filed motions to dismiss with the court. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS, the Company and the other Four Corners participants may reinstate the motions to dismiss. On February 14, 2014, the parties filed a joint motion to extend the stay in the case by 30 days holding the matter in abeyance until March 17, 2014. The Company is unable to predict the outcome of this litigation.

Construction Program

Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.

The Company’s estimated cash construction costs for 2014 through 2018 are approximately $1.3 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.



By Year (1)(2) (estimates in millions)			By Function (estimates in millions)
2014	$	327	Generation (1)(2)	$	584
2015	256		Transmission	193
2016	249		Distribution	317
2017	209		General (3)	180
2018	233
Total	$	1,274	Total	$	1,274

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__________________________


(1)	Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."

(2)

$345 million has been allocated for new generating capacity of which $214 million is to construct four units of the Montana Power Station (the "MPS"). The $214 million consist of $63 million to complete construction of two 88 MW gas-fired LMS-100 units that are scheduled to come on line before the summer peak in 2015 and $151 million for two additional 88 MW gas fired LMS-100 units scheduled to come on line before the summer peak in 2016 and 2017. An additional $17 million of common costs is associated with the development of the MPS. The construction costs for the four units of the MPS may increase, and the construction schedule, associated expenditures and the in-service dates could be delayed, if the Company does not receive non-appealable air permits by the end of the third quarter of 2014. For a full discussion of the MPS air permits see "Regulation-Texas Regulatory Matters-Montana Power Station Approvals". In addition to the construction costs for the MPS, $114 million of construction costs are included from 2016 through 2018 for a combined cycle unit scheduled to be phased in over the 2019 to 2021 time frame. In addition to construction costs for new generating capacity, generation costs include $44 million for other local generation, $16 million for Four Corners (which excludes costs for pollution control equipment that would be placed in service after the Company’s planned exit in July 2016), and $179 million for the Palo Verde Station. The Company currently intends to retire Rio Grande Power Station Unit 6 (“Rio Grande 6”) before the 2015 summer peak. Rio Grande 6 is a 45 MW steam-electric generating unit which was originally placed in service in 1957. The Company may decide to extend the life of Rio Grande 6 should the construction schedule of MPS be delayed. Additionally, as noted above, the Company intends to cease its participation in Four Corners in 2016.


(3)	Includes $33 million for a new distribution center, which will be located at the MPS.

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Energy Sources

General

The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by Company-owned solar photovoltaic panels and wind turbines accounted for less than 1% of the total kWh energy mix.



	Years Ended December 31,
	2013		2012		2011
Power Source	(percentage of energy mix)
Nuclear	46	%	46	%	45	%
Natural gas	34		32		30
Coal	6		6		6
Purchased power	14		16		19
Total	100	%	100	%	100	%

Allocated fuel and purchased power costs are generally recoverable from customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC"). See "Regulation – Texas Regulatory Matters" and "– New Mexico Regulatory Matters."

Nuclear Fuel

The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"); the enrichment of uranium hexafluoride ("enrichment services"); the fabrication of fuel assemblies ("fabrication services"); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel.

Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for 100% of Palo Verde's requirements for uranium concentrates through 2017, 90% of its requirements in 2018 and 45% of its requirements in 2019-2020. The participants have also contracted for all of Palo Verde's conversion services through 2016 and 95% of its requirements in 2017-2018 and 45% of its requirements in 2019-2020. In addition, all of Palo Verde's enrichment services through 2020 have been contracted and all of Palo Verde's fuel assembly fabrication services through 2016 are under contract.

Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $110 million aggregate principal amount borrowed through senior notes. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and amounts borrowed under the revolving credit facility (the "RCF").

Natural Gas

The Company manages its natural gas requirements through a combination of a long-term supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. In 2013, the Company’s natural gas requirements at the Newman and Rio Grande Power Stations were met with both short-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2014. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include the MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for the Newman and Rio Grande Power Stations. The Company will continue to evaluate the availability of short-term natural gas supplies versus long-term supplies to maintain a reliable and economical supply for the Newman and Rio Grande Power Stations.

Natural gas for the Newman and Copper Power Stations is also supplied pursuant to an intrastate natural gas contract that became effective October 1, 2009 and continues through 2017.

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Coal

APS, as operating agent for Four Corners, purchases Four Corners' coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation.

On December 30, 2013, APS and Southern California Edison ("SCE") closed their previously announced transaction whereby APS agreed to purchase SCE's 48% interest in Units 4 and 5 of Four Corners. Concurrently with the closing of this transaction, the ownership of BHP Navajo Coal Company, the coal supplier and operator of the mine that serves Four Corners, was transferred to Navajo Transitional Energy Company, LLC ("NTEC"), a company formed by the Navajo Nation to own the mine and develop other energy projects.

Purchased Power

The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to 125 MW at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2014. The contract was approved by the FERC and continues through December 31, 2021.

The Company entered into an agreement in 2009 to purchase capacity of up to 40 MW and unit contingent energy during 2010 from Shell Energy North America ("Shell"). Under the agreement, the Company provides natural gas to Pyramid Unit No. 4 where Shell has the right to convert natural gas to electric energy. The Company entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014.

The Company entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 (10 MW) and SunEdison 2 (12 MW) which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements.

In May 2013, the NMPRC approved the Company's agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico. The term of the purchased power agreement is 20 years from the commercial operation date of the Macho Springs project which is projected to be May 1, 2014. In addition, on September 5, 2013, the Company entered into a purchased power agreement with Newman Solar LLC to purchase, for a term of 30 years, the total output from a solar photovoltaic generation facility of approximately 10 MW that Newman Solar LLC will construct, own and operate on land subleased from the Company in proximity to its Newman Generation Station. This solar project is expected to be on line at the end of 2014.

Other purchases of shorter duration were made during 2013 to supplement the Company's generation resources during planned and unplanned outages and for economic reasons as well as to supply off-system sales.

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Operating Statistics



	Years Ended December 31,
	2013		2012			2011
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	236,651	$	234,095		$	234,086
Commercial and industrial, small	184,568		188,014			196,093
Commercial and industrial, large	40,235		42,041			45,407
Sales to public authorities	95,044		96,132			94,370
Total retail base revenues	556,498		560,282			569,956
Wholesale:
Sales for resale	2,172		2,318			2,122
Total non-fuel base revenues	558,670		562,600			572,078
Fuel revenues:
Recovered from customers during the period	133,481		130,193			145,130
Under (over) collection of fuel	10,849		(18,539		)	13,917
New Mexico fuel in base rates	73,295		74,154			73,454
Total fuel revenues	217,625		185,808			232,501
Off-system sales:
Fuel cost	68,241		62,481			74,736
Shared margins	13,016		9,191			3,883
Retained margins	1,549		1,098			(560		)
Total off-system sales	82,806		72,770			78,059
Other	31,261		31,703			35,375
Total operating revenues	$	890,362	$	852,881		$	918,013
Number of customers (end of year) (1):
Residential	349,629		345,567			339,860
Commercial and industrial, small	39,164		38,494			38,539
Commercial and industrial, large	50		50			49
Other	5,043		4,896			4,720
Total	393,886		389,007			383,168
Average annual kWh use per residential customer	7,701		7,712			7,804
Energy supplied, net, kWh (in thousands):
Generated	9,288,773		9,262,133			8,936,776
Purchased and interchanged	1,547,930		1,768,810			2,135,124
Total	10,836,703		11,030,943			11,071,900
Energy sales, kWh (in thousands):
Retail:
Residential	2,679,262		2,648,348			2,633,390
Commercial and industrial, small	2,349,148		2,366,541			2,352,218
Commercial and industrial, large	1,095,379		1,082,973			1,096,040
Sales to public authorities	1,622,607		1,617,606			1,579,565
Total retail	7,746,396		7,715,468			7,661,213
Wholesale:
Sales for resale	61,232		64,266			62,656
Off-system sales	2,472,622		2,614,132			2,687,631
Total wholesale	2,533,854		2,678,398			2,750,287
Total energy sales	10,280,250		10,393,866			10,411,500
Losses and Company use	556,453		637,077			660,400
Total	10,836,703		11,030,943			11,071,900
Native system:
Peak load, kW	1,750,000		1,688,000			1,714,000
Net dependable generating capability for peak, kW	1,852,000		1,765,000			1,785,000
Total system:
Peak load, kW (2)	1,883,000		1,979,000			1,967,000
Net dependable generating capability for peak, kW	1,852,000		1,765,000			1,785,000

___________________________

(1)

The number of retail customers presented are based on the number of service locations. Previous presentations of the number of retail customers in 2012 and 2011 were based on the number of bills rendered including consolidated bills for customers operating multiple facilities. Management believes the number of service locations provides a more accurate indicator of customers served than the number of bills rendered.


(2)	Includes spot sales and net losses of 133,000 kW, 291,000 kW and 253,000 kW for 2013, 2012 and 2011, respectively.

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Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.

On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012.

Under the terms of the settlement, among other things, the Company agreed to:


•	A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012;


•	Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually;


•	Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and


•	A two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings.

As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011 and submit a future fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier. The settlement also provides for the continuation of the energy efficiency cost recovery factor and the military base discount recovery factor. Both of these surcharges require annual filings to reconcile and revise the recovery factors.

Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

The Company filed the following petition with the PUCT to refund fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the date the Company filed the petition and the date a final order was issued by the PUCT approving the refund to customers. The fuel cost over-recovery period represents the months in which the over-recoveries took place, and the refund period represents the billing month in which customers received the refund amounts shown, including interest:

Docket

No.

Date Filed

Date Approved

Recovery Period

Refund Period

Refund Amount Authorized (In thousands)

40622

August 3, 2012

September 28, 2012

January 2011- June 2012

September 2012

6,600

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The Company filed the following petitions with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:



Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor	Effective Billing Month
40302	April 12, 2012	April 25, 2012	(18.5)%	May 2012
41803	September 9, 2013	September 23, 2013	12.2%	October 2013

Fuel Reconciliation Proceeding. On September 27, 2013, the Company filed an application with the PUCT, designated as Docket No. 41852, to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 1, 2009 through March 31, 2013. The fuel reconciliation requests to recover $3.4 million of rewards for Palo Verde operations. Intervenor testimony is due February 28, 2014 and PUCT Staff testimony is due March 7, 2014. Hearings in the fuel reconciliation are scheduled to begin March 31, 2014 and a final order must be issued by September 26, 2014.

Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") authorization from the PUCT to construct the first two (of four) units of the MPS which are scheduled to come on line before the summer peak in 2015. The Company must also obtain air permits from state and federal regulatory agencies before it can begin construction. On January 22, 2014, the Texas Commission on Environmental Quality ("TCEQ") issued the required permit. The EPA issued a draft permit for GHG in September 2013 and solicited public comment. EPA is considering comments filed in response to that proposal before issuing a final permit. The Company believes that the type of facility planned at the MPS complies with all EPA regulations for granting a GHG permit and that the issues raised in the comments have previously been resolved in proceedings in other regions in favor of the grant of a permit. If the permit is granted, commenters may challenge the determination before the U.S. EPA’s Environmental Appeals Board. While the Company believes that this application demonstrates compliance with all applicable regulations, it cannot predict the timing or final outcome.

On September 6, 2013, the Company filed an application with the PUCT for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas which are scheduled to come on line before the summer peak in 2016 and 2017. The case has been designated PUCT Docket No. 41763. Hearings in this case were held in February 2014. In accordance with PUCT rules, the final order must be issued by September 5, 2014.

The Company filed three transmission line CCN applications with the PUCT as part of the MPS Project:


•	MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360)


•	MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359)


•	MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809)

The transmission CCN filings for both the MPS to Caliente and the MPS In & Out were filed on April 15, 2013, and the transmission CCN filing for the MPS to Montwood was filed on September 24, 2013. The Company is requesting to build these transmission lines to connect the new MPS to the electrical grid in order to meet increased customer growth and electric demand and to improve system reliability. A final order approving a unanimous settlement in the MPS to Caliente transmission CCN filing is expected by the end of the first quarter of 2014. Final orders in the transmission CCN filings for the MPS In & Out and the MPS to Montwood filings are expected no later than October 2014.

Other Required Approvals. The Company has obtained other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the Public Utility Regulatory Act ( the "PURA") and the PUCT.

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New Mexico Regulatory Matters

2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures which requires an annual filing and approval of the related incentives and adjustment to the recovery factors.

Fuel and purchased power costs in New Mexico are recovered through a Fuel and Purchased Power Cost Recovery Factor (the "FPPCAC"). On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification. The Company recovers its investment in Palo Verde Unit 3 in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2009 New Mexico rate stipulation.

2013 Annual Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2013, the Company filed its application for approval of its 2013 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act. On November 20, 2013, the NMPRC issued a final order approving the renewable procurement plan with modifications recommended by the Hearing Examiner. The plan sets out the Company's procurement of renewable resources and estimated costs for 2014 and 2015 to meet Renewable Portfolio Standards ("RPS") and resource diversity requirements. The approved plan provides for the RPS and diversity requirements for 2014 and 2015 to be met with a combination of previously approved resources and grants the Company's request for waiver for meeting the full RPS through 2015 due to reasonable cost threshold limits. The order also grants the Company's requested diversity variances for 2014 and 2015. Costs for purchases of renewable energy delivered to the Company are recovered through the FPPCAC and purchases of unbundled renewable energy credits are recovered through base rates.

Long-Term Purchased Power Agreement with Macho Springs. On November 21, 2012, the Company filed an application with the NMPRC requesting approval of a Long-Term Purchase Power Agreement (the "LTPPA") with Macho Springs Solar, LLC ("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs on the Company's New Mexico transmission system. The Company also sought approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. A final order approving the LTPPA and recovery through the FPPCAC was received May 1, 2013.

Montana Power Station Approvals. The Company has received a CCN authorization from the NMPRC to construct the first two (of four) units of the MPS. As discussed above, the Company must also obtain air permits from the TCEQ and EPA before it can begin construction. On September 6, 2013, the Company filed an application with the NMPRC for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case has been designated NMPRC Case No. 13-00297-UT. No protests to the Company's application were filed and the hearing examiner issued a recommended decision to approve the Company's application on February 20, 2014. A final order is expected in the first quarter of 2014.

Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On October 30, 2013, the Company received approval in NMPRC Case No. 13-00317-UT to amend its current $300 million RCF to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years ; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the financing of purchases of nuclear fuel.

On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. Under the terms of the agreement, the Company has available $300 million and the ability to increase the RCF by up to $100 million (up to a total of $400 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. The RCF has a term ending January 2019. The Company may extend the maturity date up to two times, in each case for an additional one year period upon the satisfaction of certain conditions.

Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, long-term resource plans, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.

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Federal Regulatory Matters

Public Service Company of New Mexico's ("PNM") 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Change for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million for amounts that PNM collected since June 1, 2011 in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense.

Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On September 30, 2013, the Company filed an application for approval to amend its current $300 million RCF to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the purchase of nuclear fuel. The FERC issued an order approving the filing on November 15, 2013. The case was assigned to FERC Docket No. ES 13-59-000. As noted above, on January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF.

Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.

Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comision Federal de Electricidad in Mexico pursuant to a license granted by the DOE and a presidential permit.

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Facilities-Palo Verde Station for discussion of spent fuel storage and disposal costs.

Sales for Resale

The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2014.

Franchises and Significant Customers

El Paso and Las Cruces Franchises

The Company has a franchise agreement with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso. The Company is also providing electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009.

The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below:



City	Period	Franchise Fee	(a)
El Paso	August 1, 2010 - Present	4.00%	(b)
Las Cruces	February 1, 2000 - Present	2.00%

(a) Based on a percentage of revenue.

(b) 0.75% of the El Paso franchise fee is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.

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Military Installations

The Company serves Holloman Air Force Base ("Holloman"), White Sands Missile Range ("White Sands") and Fort Bliss. The military installations represent approximately 5% of the Company's annual retail revenues. Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company is serving White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016.

Other Information

Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on new guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about our company. It is possible that the financial information we post there could be deemed to be material information. The information on our website is not part of this document.

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Executive Officers of the Registrant

The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors. The executive officers of the Company as of February 26, 2014, were as follows:



Name	Age	Current Position and Business Experience
Thomas V. Shockley III	68	Chief Executive Officer since May 2012; Interim Chief Executive Officer from January 2012 to May 2012; Non-Employee Member of the Board of Directors from May 2010 to January 2012; Vice – Chairman and Chief Operating Officer for American Electric Power from June 2000 to August 2004; retired in 2004.
David G. Carpenter	58	Executive Vice President since October 2013; Senior Vice President and Chief Financial Officer from August 2009 to October 2013; Vice President – Regulatory Services and Controller from September 2008 to August 2009.
Hector R. Puente	57	Executive Vice President since October 2013; Senior Vice President and Chief Operations Officer from June 2012 to October 2013; Senior Vice President – Operations from May 2011 to May 2012; Vice President – Transmission and Distribution from January 2006 to May 2011.
Steven T. Buraczyk	46	Senior Vice President – Operations since October 2013;Vice President of Regulatory Affairs from April 2013 to October 2013; Vice President of Power Marketing and Fuels and Resource and Delivery Planning from August 2012 to April 2013; Vice President – System Operations and Planning from January 2011 to August 2012; Vice President – Power Marketing and Fuels from July 2008 to January 2011.
Nathan T. Hirschi	50	Senior Vice President and Chief Financial Officer since October 2013;Vice President and Controller from March 2010 to October 2013; Vice President – Special Projects from December 2009 to February 2010; Partner for KPMG LLP from October 2003 to April 2009.
Mary E. Kipp	46	Senior Vice President, General Counsel and Chief Compliance Officer since June 2010; Vice President – Legal and Chief Compliance Officer from December 2009 to June 2010; Assistant General Counsel and Director of FERC Compliance from December 2007 to December 2009.
Rocky R. Miracle	61	Senior Vice President – Corporate Planning and Development since August 2009; Vice President – Corporate Planning from September 2008 to August 2009.

Item 1A. Risk Factors

Like other companies in our industry, our financial results will be impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Our Revenues and Profitability Depend upon Regulated Rates

Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC Case No. 09‑00171‑UT, established rates in New Mexico that became effective on January 2010.

Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including

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costs associated with future plant retirement and asset retirement obligations. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.

We May Not Be Able To Recover All Costs of New Generation

During 2013, we completed the construction of Rio Grande Unit 9, an aeroderivative unit with a generating capacity of 87 MW, which reached commercial operation in May 2013. In addition, we have received approval from both the PUCT and the NMPRC of the CCN to construct the first two units of the Montana Power Station, a new plant site, which will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines. We have risk related to recovering all costs associated with the construction of Rio Grande Unit 9 and other new units.

In 2012, we issued $150 million in aggregate principal amount of 3.30% Senior Notes, due December 15, 2022. The 3.30% Senior Notes along with our revolving credit facility, which was amended and restated on January 14, 2014, could help fund the construction of the Montana Power Station and other new units. The costs of financing and constructing these units will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.

In addition, if these units are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units.

Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning

In recent years, the global credit and equity markets and the overall economy have been through a state of turmoil. These and future events could have a number of effects on our operations and our capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates which we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and shutdown.The credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events, could impact our ability to fund construction expenditures and impact the level of dividend payments. This is not intended to be an exhaustive list of possible effects, and we may be adversely impacted in other ways.

Our Costs Could Increase or We Could Experience Reduced Revenues if

There are Problems at the Palo Verde Nuclear Generating Station

A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our 15.8% interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 34% of our available net generating capacity and provided approximately 46% of our energy requirements for the twelve months ended December 31, 2013. Palo Verde comprises approximately 29% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 91.1% and 92.3% in the twelve months ended December 31, 2013 and 2012, respectively.

Our ability to increase retail base rates in Texas and New Mexico is limited. We cannot assure that revenues will be sufficient to recover any increased costs, including any increased costs in connection with Palo Verde or other operations, whether as a result

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of inflation, changes in tax laws, regulatory requirements, the costs of securing the facilities against possible terrorist attacks, or other causes.

We May Not Be Able to Recover All of Our Fuel Expenses from Customers

In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased power contract. Fuel and purchased power expenses in New Mexico and Texas are subject to reconciliation by the PUCT and NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the repriced energy costs for Palo Verde Unit 3 in New Mexico. In September 2013, we filed an application with the PUCT (Docket No. 41852), to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 2009 through March 31, 2013. In the event that recovery of fuel and purchased power expenses is denied in this or future reconciliation proceedings, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.

In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow. At December 31, 2013 and 2012, the Company had a net under-collection balance of $6.2 million and a net over-collection balance of $4.6 million, respectively.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. Concerns over physical security of transmission lines is also increasing, which may require us to incur additional capital and operating costs. Damage to certain transmission facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as interest rates, economic conditions, fuel prices and price volatility, are largely beyond our control, but may have a material adverse effect on our earnings, cash flow and financial position.

Competition and Deregulation Could Result in a Loss of Customers and Increased Costs

As a result of changes in federal law, our wholesale and large retail customers already have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if they are achieved at all. There is substantial

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uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.

Future Costs of Compliance with Environmental Laws and Regulations Could

Adversely Affect Our Operations and Financial Results

We are or may become subject to extensive federal, state and local environmental statutes, rules and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of air quality control equipment and purchases of air emission allowances and/or offsets. These could also result in limitations in operating hours and/or changes in construction schedules for future generating units.

Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and/or financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental rules or regulations. For example, the EPA has issued in the recent past various final and proposed regulations regarding air emissions from our operations as well as the rest of the utility sector, including the Cross-Sate Air Pollution Rule and the GHG New Source Performance Standard ("NSPS") for Electric Generating Units. If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.

Compliance with environmental laws and regulations also adds uncertainty to the timing and costs of our future generation additions. We filed separate air permit applications for the MPS, our proposed new generation facility in far east El Paso, with the TCEQ and the EPA in April 2012. TCEQ issued a final permit on January 22, 2014, following a contested case process. The application filed with the EPA yielded a draft permit in September 2013, a public hearing on October 24, 2013, and a public comment period that ended December 4, 2013. While a final permit from the EPA regional office is expected in a few months, this process could be extended if an Environmental Appeals Board review is requested. While we believe that this application demonstrates compliance with all applicable regulations, we cannot predict the timing or final outcome.

Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for

Electricity or Availability of Resources, and Could Result in Increased Compliance Costs

The Company emits GHGs through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate the emission of GHGs and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, the EPA began requiring permits for GHG emissions from certain stationary sources, including most power plants, in January 2011. The U.S. Supreme Court held oral argument on February 24, 2014, regarding the legality of these permitting requirements. Regardless of the outcome, the EPA plans to exercise other EPA GHG rulemaking authority. For example, on January 8, 2014, the EPA published a proposal to establish new source performance standards limiting GHG emission from electric generating units on which construction commences after that date. The EPA is also in the early stages of developing NSPS for existing sources based on its eventual adoption of NSPS for new sources. The potential impact of these rules (if finalized) on the Company is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.

It is not currently possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any such regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.

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Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business

We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business.

Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs, require us to make capital expenditures or otherwise harm our business.

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Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-ways, easements, or on streets or highways by public consent.

The Company owns an executive and administrative office building in El Paso. The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. The Company also leases certain warehouse facilities in El Paso under a lease which expires in December 2015. The Company has several other leases for office and parking facilities which expire within the next four years.


Item 3.	Legal Proceedings

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

See "Environmental Matters" and "Regulation" for discussion of the effects of government legislation and regulation on the Company.


Item 4.	Mine Safety Disclosures

Not Applicable.

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PART II


Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE". The intraday high, intraday low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the NYSE, and quarterly dividends per share paid by the Company for the periods indicated below were as follows:



	Sales Price
	High		Low		Close		Dividends
					(End of period)
2012
First Quarter	$	35.34	$	31.58	$	32.49	$	0.22
Second Quarter	33.65		29.17		33.16		0.25
Third Quarter	34.93		32.45		34.25		0.25
Fourth Quarter	35.01		30.15		31.91		0.25
2013
First Quarter	$	34.18	$	31.84	$	33.65	$	0.25
Second Quarter	38.91		32.47		35.31		0.265
Third Quarter	39.12		32.26		33.40		0.265
Fourth Quarter	36.18		32.43		35.11		0.265

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Performance Graph

The following graph compares the performance of the Company’s common stock to the performance of Edison Electric Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2008 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return, assuming reinvestment of dividends, as compared to EEI and the NYSE Composite, as reflected in the graph.



	12/31/2008	12/31/2009	12/31/2010	12/31/2011	12/31/2012	12/31/2013
EE	100	112	152	194	184	209
EEI Index	100	111	119	142	145	164
NYSE Composite	100	125	138	130	147	181

As of January 31, 2014, there were 2,677 holders of record of the Company’s common stock. The Company has been paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $42.0 million in cash dividends during the twelve months ended December 31, 2013. On January 23, 2014, the Board of Directors declared a quarterly cash dividend of $0.265 per share payable on March 31, 2014 to shareholders of record on March 14, 2014. The Board of Directors plans to review the Company's dividend policy annually in the second quarter of each year. We are currently targeting a payout ratio of approximately 45%. Declaration and payment of dividends is subject to compliance with certain financial ratios under Texas law. Since 1999, the Company has also returned cash to stockholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2013 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to October 31, 2013	—	$	—	—	393,816
November 1 to November 30, 2013	—	—		—	393,816
December 1 to December 31, 2013	4,930	35.11		—	393,816

_____________________

(a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of

restricted stock held by our employees, not considered part of the 2011 Plan.

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For Equity Compensation Plan Information see Part III, Item 12 – Security Ownership of Certain Beneficial Owners and Management.

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Item 6.Selected Financial Data

As of and for the following periods (in thousands except for share and per share data):



	Years Ended December 31,
	2013		2012		2011		2010		2009
Operating revenues	$	890,362	$	852,881	$	918,013	$	877,251	$	827,996
Operating income	165,635		$	168,658	$	190,803	$	168,962	$	133,165
Income before extraordinary items	$	88,583	$	90,846	$	103,539	$	90,317	$	66,933
Extraordinary gain, net of tax (a)	$	—	$	—	$	—	$	10,286	$	—
Net income	$	88,583	$	90,846	$	103,539	$	100,603	$	66,933
Basic earnings per share:
Income before extraordinary items	$	2.20	$	2.27	$	2.49	$	2.08	$	1.50
Extraordinary gain (a)	$	—	$	—	$	—	$	0.24	$	—
Net income	$	2.20	$	2.27	$	2.49	$	2.32	$	1.50
Weighted average number of shares outstanding	40,114,594		39,974,022		41,349,883		43,129,735		44,524,146
Diluted earnings per share:
Income before extraordinary items	$	2.20	$	2.26	$	2.48	$	2.07	$	1.50
Extraordinary gain (a)	$	—	$	—	$	—	$	0.24	$	—
Net income	$	2.20	$	2.26	$	2.48	$	2.31	$	1.50
Weighted average number of shares and dilutive
potential shares outstanding	40,126,647		40,055,581		41,587,059		43,294,419		44,595,067
Dividends declared per share of common stock	$	1.045	$	0.97	$	0.66	$	—	$	—
Cash additions to utility property, plant and equipment	$	237,411	$	202,387	$	178,041	$	169,966	$	209,974
Total assets	$	2,786,288	$	2,669,050	$	2,396,851	$	2,364,766	$	2,226,152
Long-term debt and financing obligations, net of
current portion	$	999,620	$	999,535	$	816,497	$	849,745	$	804,975
Common stock equity	$	943,833	$	824,999	$	760,251	$	810,375	$	722,729

______________________


(a)	Extraordinary gain for 2010 represents a $10.3 million extraordinary gain or $0.24 earnings per share related to Texas regulatory assets.

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Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

As you read this Management’s Discussion and Analysis, please refer to our Financial Statements and the accompanying notes, which contain our operating results.

Summary of Critical Accounting Policies and Estimates

Our financial statements have been prepared in conformity with Generally Accepted Accounting Principles ("GAAP"). Note A to the financial statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2013, we had recorded regulatory assets currently subject to recovery in future rates of approximately $101.1 million and regulatory liabilities of approximately $26.4 million as discussed in greater detail in Note D of the Notes to the Financial Statements. In the event we determine that we can no longer apply the FASB guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, we could be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. Such an action could materially reduce our shareholders' equity.

Collection of Fuel Expense

In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT and the NMPRC. Prior to the completion of a reconciliation proceeding, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the ANPP Participation Agreement and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates. We determine how we will fund our share of those estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. Decommissioning costs will be adjusted prospectively for future changes in estimated decommissioning costs and when actual costs are incurred to decommission the plant. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the plant increase, we could be required to increase our funding to the decommissioning trust accounts. Historically, we have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning.

Future Pension and Other Postretirement Obligations

Our obligations to retirees under various benefit plans are recorded as a liability on the balance sheets. Our liability is calculated on the basis of significant assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. Changes in these assumptions could have a material impact on both net income and on the amount of liabilities reflected on the balance sheets.

Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we

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must make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation, or audit adjustments can materially affect amounts we recognize in our financial statements.

Overview

The following is an overview of our results of operations for the years ended December 31, 2013, 2012 and 2011. Net income for the years ended December 31, 2013, 2012 and 2011 is shown below:



	Years Ended December 31,
	2013		2012		2011
Net income (in thousands)	$	88,583	$	90,846	$	103,539
Basic earnings per share	2.20		2.27		2.49

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The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item between the calendar years ended 2013 and 2012, 2012 and 2011, and 2011 and 2010 (in thousands):



	2013				2012				2011
Prior year December 31 income before extraordinary item	$	90,846			$	103,539			$	90,317
Change in (net of tax):
Increased interest on long-term debt (net of capitalized interest)	(2,651		)	(a)	(252		)		(377		)
Increased (decreased) retail non-fuel base revenues	(2,497		)	(b)	(6,385		)	(c)	21,198			(d)
Increased administrative and general expense	(2,042		)	(e)	(5,730		)	(f)	(1,342		)
Income tax benefit	1,200			(g)	—				4,787			(h)
Decreased (increased) customer care expense	1,104			(i)	2,192			(i)	(2,069		)	(j)
Increased (decreased) deregulated Palo Verde Unit 3 revenues	1,039			(k)	(3,282		)	(l)	(808		)
Increased (decreased) AFUDC	900			(m)	1,745			(m)	(3,804		)	(n)
Decreased (increased) operations and maintenance at fossil fuel generating plants	763				(1,532		)		(3,725		)	(o)
Increased (decreased) off-system sales margins retained	298				1,095				(3,935		)	(p)
Increased (decreased) transmission wheeling revenue	137				(1,785		)		3,197			(q)
Other	(514		)		1,241				100
Current year December 31 net income	$	88,583			$	90,846			$	103,539

______________________


(a)	Interest on long-term debt increased in 2013 compared to 2012 primarily due to interest on $150 million of 3.3% senior notes issued in December 2012 partially offset by the refunding and remarketing of two series of pollution control bonds at lower rates in August 2012.

(b)

Retail non-fuel base revenues decreased in 2013 compared to 2012 primarily due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers reflecting the reduction in non-fuel base rates in Texas effective on May 1, 2012, and a 1.1% decrease in retail non-fuel base revenues from sales to pubic authorities. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates.

(c)

Retail non-fuel base revenues decreased in 2012 compared to 2011 primarily due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customer due to a reduction in non-fuel base rates in Texas effective May 1, 2012, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers.


(d)	Retail non-fuel base revenues increased in 2011 compared to 2010 primarily due to a 3.1% increase in kWh sales to retail customers reflecting hotter summer weather with higher non-fuel base summer rates and 1.4% growth in the average number of retail customers served in 2011.


(e)	Administrative and general expenses increased in 2013 compared to 2012 primarily due to increased outside services related to software systems support and improvements and increased consulting and legal services related to the analysis of our future involvement at the Four Corners Generating Station.


(f)	Administrative and general expenses increased in 2012 compared to 2011 primarily due to increased pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our retiree benefit plans.


(g)	Income tax benefit of $2.7 million recorded in 2013 related to positive developments related to state income tax audits and settlements partially offset by a $1.5 million tax benefit recorded in the same period last year.


(h)	A one-time charge to income tax expense was incurred in 2010 to recognize a change in tax law enacted in the Patient Protection and Affordable Care Act to eliminate the tax benefit related to the Medicare Part D subsidies with no comparable tax expense in 2011.


(i)	Customer care expense decreased in 2013 compared to 2012 and 2012 compared to 2011 primarily due to a decrease in the provision for uncollectible accounts reflecting improved collection efforts.


(j)	Customer care expense increased in 2011 compared to 2010 primarily due to increased costs for customer-related activities, an increase in uncollectible customer accounts, and an increase in payroll costs.


(k)	Deregulated Palo Verde Unit 3 revenues in 2013 increased compared to 2012 due to a 19.2% increase in power prices partially offset by an 8.5% increase in the costs of nuclear fuel and a 3.8% decrease in generation.


(l)	Deregulated Palo Verde Unit 3 revenues in 2012 reflect lower proxy market prices associated with the decline in natural gas prices and lower sales of the deregulated portion of Palo Verde Unit 3 to retail customers due mostly to its planned refueling outage in March and April 2012, and also reflect an increase in the costs of nuclear fuel.

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(m)	AFUDC (allowance for funds used during construction) increased primarily due to higher balances of construction work in progress subject to AFUDC primarily reflecting construction of Rio Grande Unit 9 placed in service in May 2013.


(n)	AFUDC decreased in 2011 compared to 2010 primarily due to lower balances of construction work in progress subject to AFUDC reflecting the completion and placing in service the Newman Unit 5 Phase II generating plant in April 2011.


(o)	Operations and maintenance at gas-fired fuel generating stations increased in 2011 compared to 2010 largely as a result of weather-related damage during severe winter weather in February 2011 and freeze protection upgrades.


(p)	Off-system sales margins decreased in 2011 compared to 2010 primarily due to lower average market prices for power and an increase in sharing of off-system sales margins with customers from 25% to 90% effective in July 2010.


(q)	Transmission revenues increased in 2011 compared to 2010 primarily due to a settlement agreement with Tucson Electric Power Company resolving a transmission dispute that resulted in a one-time adjustment to income of $3.9 million, pre-tax and annual revenue of $1.1 million per year.

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Historical Results of Operations

The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations. The amounts presented below are presented on a pre-tax basis.

Operating revenues

We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale (which are FERC-regulated cost-based wholesale sales within our service territory) accounted for less than 1% of revenues in each of 2013, 2012 and 2011.

Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. A significant portion of fuel costs are also recovered through base rates in New Mexico. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.

Retail non-fuel base revenue percentages by customer class are presented below:



	Years Ended December 31,
	2013		2012		2011
Residential	43	%	42	%	41	%
Commercial and industrial, small	33		34		34
Commercial and industrial, large	7		7		8
Sales to public authorities	17		17		17
Total retail non-fuel base revenues	100	%	100	%	100	%

No retail customer accounted for more than 4% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 75% or more of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structure in New Mexico and Texas reflects higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:



	Years Ended December 31,
	2013		2012		2011
January 1 to March 31	20	%	19	%	18	%
April 1 to June 30	27		27		27
July 1 to September 30	33		33		34
October 1 to December 31	20		21		21
Total	100	%	100	%	100	%

Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to public authorities. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. The table below shows heating and cooling degree days compared to a 10-year average for 2013, 2012 and 2011.



	2013	2012	2011	10-year Average
Heating degree days	2,426	2,009	2,402	2,247
Cooling degree days	2,695	2,876	3,135	2,633

Cooling degree days decreased 6.3% for the twelve months ended December 31, 2013 when compared to the same period in 2012 and 14.0% for the twelve months ended December 31, 2013 when compared to the same period in 2011. Total cooling degree days in 2013 were at its lowest level since 2008.

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Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.3% in 2013 and 1.8% in 2012. See the tables presented on pages 33 and 34 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. The rate structure effective July 1, 2010 through April 30, 2012 in Texas was based on the final order in PUCT Docket No. 37690. On April 17, 2012, the El Paso City Council (the "Council") approved the settlement of our 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094 and on April 26, 2012, the administrative law judge issued an order implementing the settlement rates as temporary rates effective May 1, 2012. The PUCT approved the settlement on May 18, 2012. Under the terms of the settlement, among other things, we agreed to a reduction in our non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes.

Retail non-fuel base revenues decreased by $3.8 million, or 0.7% for the twelve months ended December 31, 2013 when compared to the same period in 2012. The decrease in retail non-fuel base revenues was primarily due to decreased revenues from our commercial and industrial customers which reflect the impact of the reduction in non-fuel base rates for our Texas customers which became effective May 1, 2012. Non-fuel base revenues from sales to small commercial and industrial and large commercial and industrial customers decreased 1.8% and 4.3%, respectively. Retail non-fuel base revenues from sales to public authorities decreased 1.1%. While the kWh sales to public authorities increased by 0.3% in 2013 compared to 2012, revenues from this customer class reflect the impacts of recently installed solar photovoltaic generation at Fort Bliss and White Sands Missile Range. Additionally, 2013 revenues were negatively impacted by the federal government sequestration and shutdown in October 2013. KWh sales to small commercial and industrial customers decreased 0.7%. The decrease in retail non-fuel base revenues was partially offset by an increase of 1.1% in non-fuel base revenues from sales to residential customers reflecting a 1.2% increase in kWh sales to our residential customer class. The increase in kWh sales to our residential customers reflects a 1.3% increase in the average number of residential customers served. We experienced less favorable weather during our summer cooling season. Cooling degree days decreased 6.3% when compared to the same period in 2012 but were higher than the 10-year average by 2.4%. Heating degree days increased 20.8% over 2012 and were 8.0% higher than the 10-year average.

Retail non-fuel base revenues decreased by $9.7 million or 1.7% for the twelve months ended December 31, 2012 when compared to the same period in 2011. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 4.1% and 7.4%, respectively, which reflect the impact of the reduction in non-fuel base rates for our Texas customers which became effective May 1, 2012. In addition, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers contributed to the decrease in non-fuel base revenues. KWh sales to large commercial and industrial customer decreased 1.2%. KWh sales to small commercial and industrial customers increased 0.6% primarily due to the 1.6% increase in the average number of customers served. KWh sales to residential customers increased 0.6% due to the 1.8% increase in the average number of customers served despite milder weather in 2012 compared to 2011. KWh sales to public authorities increased 2.4% and non-fuel base revenues from public authorities increased 1.9% compared to 2011.

Fuel revenues. Fuel revenues consist of: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs.

We under-recovered fuel costs by $10.8 million in the twelve months ended December 31, 2013. We over-recovered fuel costs by $18.5 million in the twelve months ended December 31, 2012 and we under-recovered fuel costs by $13.9 million in the twelve months ended December 31, 2011. Refunds of $6.9 million and $12.0 million were returned to our Texas customers in the twelve months ended December 31, 2012 and 2011, respectively. At December 31, 2013, we had a net fuel under-recovery balance of $6.2 million, including an under-recovery balance of $7.2 million in Texas and an over-recovery balance of $1.0 million in New Mexico. Over-recoveries in New Mexico will be refunded through our fuel adjustment clause during 2014.

Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We share 90% of off-system sales margins with our Texas and New Mexico customers, and we retain 10% of off-system sales margins. We are sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a contract.

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Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins.

The table below shows MWhs, sales revenue, fuel costs, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2013, 2012 and 2011 (in thousands except for MWhs).



	Years Ended December 31,
	2013		2012		2011
MWh sales	2,472,622		2,614,132		2,687,631
Sales revenues	$	82,806	$	72,770	$	78,059
Fuel cost	$	68,241	$	62,481	$	74,736
Total margins	$	14,565	$	10,289	$	3,323
Retained margins	$	1,549	$	1,098	$	(560	)

Off-system sales revenues increased $10.0 million or 13.8% for the twelve months ended December 31, 2013 when compared to the same period in 2012 as a result of higher average market prices for power partially offset by a 5.4% decline in MWh sales. Off-system sales revenues decreased $5.3 million or 6.8% for the twelve months ended December 31, 2012 when compared to 2011 as a result of lower average market prices for power and a 2.7% decline in MWh sales. For the twelve months ended December 31, 2013, retained margins increased $0.5 million when compared to the same period in 2012. For the twelve months ended December 31, 2012, retained margins increased $1.7 million when compared to the same period in 2011 primarily due to the negative impacts in 2011 of power purchases required for system reliability when key generation and transmission facilities were either out of service or were threatened to be out of service.

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Comparisons of kWh sales and operating revenues are shown below:



						Increase (Decrease)
Years Ended December 31:	2013		2012			Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,679,262		2,648,348			30,914			1.2	%
Commercial and industrial, small	2,349,148		2,366,541			(17,393		)	(0.7	)
Commercial and industrial, large	1,095,379		1,082,973			12,406			1.1
Sales to public authorities	1,622,607		1,617,606			5,001			0.3
Total retail sales	7,746,396		7,715,468			30,928			0.4
Wholesale:
Sales for resale	61,232		64,266			(3,034		)	(4.7	)
Off-system sales	2,472,622		2,614,132			(141,510		)	(5.4	)
Total wholesale sales	2,533,854		2,678,398			(144,544		)	(5.4	)
Total kWh sales	10,280,250		10,393,866			(113,616		)	(1.1	)
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	236,651	$	234,095		$	2,556		1.1	%
Commercial and industrial, small	184,568		188,014			(3,446		)	(1.8	)
Commercial and industrial, large	40,235		42,041			(1,806		)	(4.3	)
Sales to public authorities	95,044		96,132			(1,088		)	(1.1	)
Total retail non-fuel base revenues	556,498		560,282			(3,784		)	(0.7	)
Wholesale:
Sales for resale	2,172		2,318			(146		)	(6.3	)
Total non-fuel base revenues	558,670		562,600			(3,930		)	(0.7	)
Fuel revenues:
Recovered from customers during the period (1)	133,481		130,193			3,288			2.5
Under (over) collection of fuel	10,849		(18,539		)	29,388			—
New Mexico fuel in base rates	73,295		74,154			(859		)	(1.2	)
Total fuel revenues (2)	217,625		185,808			31,817			17.1
Off-system sales:
Fuel cost	68,241		62,481			5,760			9.2
Shared margins	13,016		9,191			3,825			41.6
Retained margins	1,549		1,098			451			41.1
Total off-system sales	82,806		72,770			10,036			13.8

Other (3)	31,261		31,703			(442		)	(1.4	)
Total operating revenues	$	890,362	$	852,881		$	37,481		4.4
Average number of retail customers (4):
Residential	347,891		343,409			4,482			1.3	%
Commercial and industrial, small	38,836		38,601			235			0.6
Commercial and industrial, large	50		50			—			—
Sales to public authorities	4,997		4,828			169			3.5
Total	391,774		386,888			4,886			1.3

___________________________


(1)	Excludes $6.9 million of refunds in 2012 related to prior periods' Texas deferred fuel revenues.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $11.4 million and $9.8 million in 2013 and 2012, respectively.


(3)	Represents revenues with no related kWh sales.

(4)

The number of retail customers presented are based on the number of service locations. Previous presentations of the number of retail customers in 2012 were based on the number of bills rendered including consolidated bills for customers operating multiple facilities. Management believes the number of service locations provides a more accurate indicator of customers served than the number of bills rendered.

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							Increase (Decrease)
Years Ended December 31:	2012			2011			Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,648,348			2,633,390			14,958			0.6	%
Commercial and industrial, small	2,366,541			2,352,218			14,323			0.6
Commercial and industrial, large	1,082,973			1,096,040			(13,067		)	(1.2	)
Sales to public authorities	1,617,606			1,579,565			38,041			2.4
Total retail sales	7,715,468			7,661,213			54,255			0.7
Wholesale:
Sales for resale	64,266			62,656			1,610			2.6
Off-system sales	2,614,132			2,687,631			(73,499		)	(2.7	)
Total wholesale sales	2,678,398			2,750,287			(71,889		)	(2.6	)
Total kWh sales	10,393,866			10,411,500			(17,634		)	(0.2	)
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	234,095		$	234,086		$	9		—
Commercial and industrial, small	188,014			196,093			(8,079		)	(4.1	)%
Commercial and industrial, large	42,041			45,407			(3,366		)	(7.4	)
Sales to public authorities	96,132			94,370			1,762			1.9
Total retail non-fuel base revenues	560,282			569,956			(9,674		)	(1.7	)
Wholesale:
Sales for resale	2,318			2,122			196			9.2
Total non-fuel base revenues	562,600			572,078			(9,478		)	(1.7	)
Fuel revenues:
Recovered from customers during the period (1)	130,193			145,130			(14,937		)	(10.3	)
Under (over) collection of fuel	(18,539		)	13,917			(32,456		)	—
New Mexico fuel in base rates	74,154			73,454			700			1.0
Total fuel revenues (2)	185,808			232,501			(46,693		)	(20.1	)
Off-system sales:
Fuel cost	62,481			74,736			(12,255		)	(16.4	)
Shared margins	9,191			3,883			5,308			—
Retained margins	1,098			(560		)	1,658			—
Total off-system sales	72,770			78,059			(5,289		)	(6.8	)

Other (3)	31,703			35,375			(3,672		)	(10.4	)
Total operating revenues	$	852,881		$	918,013		$	(65,132	)	(7.1	)
Average number of retail customers (4):
Residential	343,409			337,440			5,969			1.8	%
Commercial and industrial, small	38,601			37,978			623			1.6
Commercial and industrial, large	50			50			—			—
Sales to public authorities	4,828			4,693			135			2.9
Total	386,888			380,161			6,727			1.8

_______________________


(1)	Excludes $6.9 million and $12.0 million of refunds in 2012 and 2011, respectively, related to prior periods' Texas deferred fuel revenues.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $14.8 million in 2012 and 2011, respectively.


(3)	Represents revenues with no related kWh sales. 2011 includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company.

(4)

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Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 34% of our available net generating capacity and approximately 53% of our Company-generated energy for the twelve months ended December 31, 2013. Fluctuations in the price of natural gas, which also is the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.

Energy expenses increased $37.8 million or 15% for the twelve months ended December 31, 2013 compared to 2012, primarily due to (i) an increase of $36.3 million in natural gas costs due to a 24% increase in the average costs of gas, and (ii) increased costs of purchased power of $2.1 million resulting from an 18.3% increase in the average price of power purchased partially offset by a 12.5% decrease in MWh purchased.

Energy expenses decreased $47.3 million or 15.9% for the twelve months ended December 31, 2012 compared to 2011, primarily due to (i) a decrease of $36.4 million in natural gas costs due to a 28% decrease in the average costs of gas partially offset by a 6% increase in MWh generated with natural gas, and (ii) decreased costs of purchased power of $14.9 million resulting from a 17% decrease in MWh purchased and a 3% decrease in the average price of power purchased. This decrease was partially offset by an increase of $5.7 million in the cost of nuclear fuel due to an 11% increase in the cost of nuclear fuel consumed and a 2% increase in MWh generated with nuclear fuel.

The table below details the sources and costs of energy for 2013, 2012 and 2011.



	2013						2012
Fuel Type	Cost			MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	164,139		3,686,823	$	44.52	$	127,833	3,561,253	$	35.90
Coal	13,680			635,717	21.52		13,604		655,108	20.77
Nuclear	48,949			4,966,233	9.86		49,639		5,045,772	9.84
Total	226,768			9,288,773	24.41		191,076		9,262,133	20.63
Purchased power	62,363			1,547,930	40.29		60,251		1,768,810	34.06
Total energy	$	289,131		10,836,703	26.68		$	251,327	11,030,943	22.78


	2011
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	164,260	(a)	3,346,789	$	50.02
Coal	15,273		(b)	647,932	19.97
Nuclear	43,974			4,942,055	8.90
Total	223,507			8,936,776	25.10
Purchased power	75,149			2,135,124	35.20
Total energy	$	298,656		11,071,900	27.05

_____________________


(a)	Natural gas costs exclude $3.2 million of energy expenses capitalized related to Newman Unit 5 pre-commercial testing recorded in 2011.


(b)	Coal costs include $2.3 million adjustment for final coal reclamation amortization in accordance with PUCT Docket No. 38361 recorded in 2011.

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Other operations expense

Other operations expense increased $0.6 million or 0.3% in 2013 compared to 2012 primarily due to increased administrative and general expense of $2.9 million due to increased outside services of $3.8 million related to software systems support and improvements and consulting and legal services related to the analysis of our future involvement at the Four Corners Generating Station. These increases were partially offset by decreased customer care expenses of $1.7 million primarily related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts and decreased power production operation expense at Palo Verde of $1.4 million.

Other operations expense increased $7.0 million or 3.0% in 2012 compared to 2011 primarily due to: (i) increased pension and benefits expense of $5.5 million reflecting changes in actuarial assumptions used to calculate expenses for our pension plans; (ii) increased power production operation expense at both Palo Verde and our fossil-fuel generating plants; and (iii) increased distribution operations expense. These increases were partially offset by decreased customer care expenses related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts.

Maintenance expense

Maintenance expenses increased $0.7 million or 1.2% in 2013 compared to 2012 due to an increase in maintenance expense for our distribution system. Maintenance expenses decreased $1.8 million or 2.8% in 2012 compared to 2011 due primarily to decreased maintenance expense at Palo Verde of $3.2 million as a result of decreased maintenance during refueling outages in 2012 compared to refueling outages in 2011 partially offset by increased maintenance expense at our fossil-fuel generating plants.

Depreciation and amortization expense

Depreciation and amortization expense increased $1.1 million or 1.4% in 2013 compared to 2012 expense due to an increase in depreciable plant including Rio Grande Unit 9. The increase was partially offset by decreased depreciation expense due to reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in May 2012.

Depreciation and amortization expense decreased $2.8 million or 3.4% in 2012 compared to 2011 due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the 2012 Texas rate case settlement discussed above. The depreciation rate reductions were partially offset by higher depreciation expense due to an increase in depreciable plant.

Taxes other than income taxes

Taxes other than income taxes increased $0.3 million or 0.5% in 2013 compared to 2012 primarily due to increased property taxes which were partially offset by a reduction in revenue related taxes. Taxes other than income taxes increased $1.9 million or 3.4% in 2012 compared to 2011 primarily due to increased revenue-related taxes and increased property taxes in New Mexico.

Other income (deductions)

Other income (deductions) increased $0.2 million or 1.5% in 2013 compared to 2012 primarily as a result of increased investment and interest income due to realized gains on equity investments in our decommissioning trusts in 2013 compared to net unrealized and realized losses on equity investments in our decommissioning trusts in 2012 and increased allowance for equity funds used during construction ("AEFUDC") due to higher balances of construction work in progress in 2013. This increase was partially offset by increased miscellaneous deductions in 2013 due to the timing and amount of charitable donations and gains recognized on the sale of assets in 2012 with no comparable amounts in 2013.

Other income (deductions) increased $2.6 million or 22.4% in 2012 compared to 2011 primarily as a result of increased AEFUDC of $1.3 million due to higher balances of construction work in progress in 2012, and a $1.1 million gain recognized on the sale of assets with no comparable amount in 2011.

Interest charges (credits)

Interest charges (credits) increased $2.8 million or 6.2% in 2013 compared to 2012 primarily due to interest on $150 million of 3.3% senior notes issued in December 2012 partially offset by (i) a decrease in interest on short-term borrowings for working capital purposes; (ii) the refunding and remarketing of two series of pollution control bonds at lower rates in August 2012; and (iii) increased allowance for borrowed funds used during construction ("ABFUDC") as a result of higher balances of construction work in progress in 2013.

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Interest charges (credits) decreased $0.1 million or 0.3% in 2012 compared to 2011 primarily due to increased ABFUDC as a result of higher balances of construction work in progress in 2012 partially offset by interest expense on the $150 million in aggregate principal amount of 3.30% Senior Notes issued in December 2012.

Income tax expense

Income tax expense decreased by $3.3 million or 7.1% in 2013 compared to 2012 primarily due to a decrease in pre-tax income and a decrease in state income taxes due to positive developments in state income tax audits and settlements. Income tax expense decreased by $6.7 million or 12.5% in 2012 compared to 2011 primarily due to a decrease in pre-tax income.

New accounting standards

In February 2013, the FASB issued new guidance (ASU 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts.

Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement to present information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income now requires the presentation in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote disclosures. ASU 2013-02 became effective prospectively for reporting periods beginning after December 15, 2012. We implemented ASU 2013-02 in the first quarter of 2013 and have presented the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) with cross-references to other disclosures or the respective line items in net income in Note H of the Notes to the Financial Statements.

In July 2013, the FASB issued new guidance (ASU 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. ASU 2013-11 is effective prospectively for all unrecognized tax benefits that exist for reporting periods beginning after December 15, 2013 and early adoption is permitted. Retrospective application is also permitted. We anticipate implementing ASU 2013-11 in the first quarter of 2014. We are currently assessing the future impact of this ASU, however it is not expected to have a significant impact on our statement of operations or statements of cash flows.

Inflation

For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations and financial condition.

Liquidity and Capital Resources

We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2013, our capital structure, including common stock, long-term debt, and short-term borrowings under the RCF, consisted of 48.2% common stock equity and 51.8% debt. At December 31, 2013, we had on hand $25.6 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations, and available borrowings under the RCF to meet all of our anticipated cash requirements for the next twelve months. We may issue long-term debt in the capital markets to finance capital requirements in 2014.

Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments, operating expenses including fuel costs, maintenance costs, and taxes.

Capital Requirements. During the twelve months ended December 31, 2013, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel.

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Projected utility construction expenditures are to expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. Rio Grande Unit 9, an aeroderivative gas turbine unit with a net dependable generating capacity of 87 MW, was completed and entered commercial operation on May 13, 2013. The total cost for this unit, including AFUDC, was approximately $95 million, of which approximately $12.4 million was incurred during 2013. We have purchased land for a new plant site, the Montana Power Station ("the MPS"), which will initially consist of two natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines. The construction costs for the four units of the MPS may increase, and the construction schedule, associated expenditures and the in-service dates could be delayed, if the Company does not receive air permits by the end of the third quarter of 2014. For a full discussion of the MPS air permits see Part I, Item 1, "Regulation". We began constructing certain components of the MPS in 2013 and the estimated costs of the first two (of four) units is $165.1 million, including AFUDC. As of December 31, 2013, we had expended $108.7 million on the MPS, including AFUDC, of which $ 73.1 million was incurred during 2013. Estimated construction expenditures for all capital projects for 2014 are approximately $327 million. See Part I, Item 1, "Business - Construction Program". Cash capital expenditures for new electric plant were $237.4 million in the twelve months ended December 31, 2013 and $202.4 million in the twelve months ended December 31, 2012.

On December 30, 2013, we paid a quarterly cash dividend of $0.265 per share or $10.7 million of quarterly dividends to shareholders of record on December 13, 2013. We paid a total of $42.0 million in cash dividends during the twelve months ended December 31, 2013. On January 23, 2014, our Board of Directors declared a quarterly cash dividend of $0.265 per share payable on March 31, 2014 to shareholders of record on March 14, 2014 which will require cash of $10.7 million. We expect to continue paying quarterly dividends during 2014 and we expect to review the dividend policy in the second quarter of 2014. At the current payout rate, we would expect to pay total cash dividends of approximately $42.8 million during 2014. In addition, while we do not currently anticipate repurchasing shares in 2014, we may repurchase common stock in the future. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased in 2013 or 2012. As of December 31, 2013, 393,816 shares remain eligible for repurchase.

We will continue to maintain a prudent level of liquidity as well as take market conditions for debt and equity securities into account. With the initiation of a dividend in early 2011, we are moving toward primarily utilizing the distribution of dividends to maintain a balanced capital structure, supplemented by share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average.

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Due to net operating loss carryforwards resulting from accelerated depreciation deductions and utilization of alternative minimum tax credits, income tax payments are expected to be minimal in 2014.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $16.9 million and $19.9 million to our retirement plans during the twelve months ended December 31, 2013 and 2012, respectively. We also contributed $3.1 million and $3.7 million to our other postretirement benefit plan during the twelve months ended December 31, 2013 and 2012, respectively. We contributed $4.5 million to our decommissioning trust funds in both 2013 and 2012. We are in compliance with the funding requirements of the federal government for our benefit plans and decommissioning trust. We will continue to review our funding for these plans in order to meet our future obligations.

Capital Resources. Cash from operations has been our primary source for funding capital requirements. Cash from operations was $247.5 million in 2013 and $273.1 million in 2012. In 2013 and 2012, cash from operations was impacted by a rate reduction in Texas. In the settlement of our 2012 Texas retail rate case in PUCT Docket No. 40094, we agreed to a reduction in our non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas commercial and industrial customer classes. The rate decrease was effective May 1, 2012, and our non-fuel base revenues were reduced by approximately $3.3 million in 2013 compared to 2012 and $11.7 million in 2012 compared to 2011 as a result of these lower rates.

Cash from operations has also been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor at least four months after our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural

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gas. On October 1, 2013, we implemented an increased fixed fuel factor charged to our Texas retail customers which was based upon a formula that reflects projected prices for natural gas.

During the twelve months ended December 31, 2013, net fuel recoveries resulted in decreased cash from operations when compared to the same period in 2012. During the twelve months ended December 31, 2013, the Company had a fuel under-recovery of $10.8 million compared to an over-recovery of fuel costs, net of refunds, of $11.7 million during the twelve months ended December 31, 2012. At December 31, 2013, we had a net fuel under-recovery balance of $6.2 million, including an under-recovery balance of $7.2 million in Texas and an over-recovery balance of $1.0 million in New Mexico.

On December 6, 2012, we issued $150 million in aggregate principal amount of 3.30% senior notes due December 15, 2022. The gross proceeds from the issuance of the senior notes were $149.7 million, net of a $0.3 million discount before commissions and expenses and the effective interest rate was 3.43%. On August 28, 2012, we completed a refunding transaction related to our 4.80% 2005 Series A (El Paso Electric Company Palo Verde Project) Pollution Control Refunding Revenue Bonds totaling $59.2 million in which new pollution control bonds totaling $59.2 million were issued at a fixed rate of 4.50%. The bonds are unsecured and will mature in 2042. On August 28, 2012, we also completed a remarketing transaction related to our 4.00% 2002 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds totaling $33.3 million in which new pollution control bonds totaling $33.3 million were issued at a fixed rate of 1.875%. These bonds were unsecured and mature in 2032 subject to mandatory tender for purchase in 2017.

We maintain an RCF for working capital and general corporate purposes and the financing of nuclear fuel through the RGRT. RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in the Company's financial statements. On January 14, 2014, we amended and extended our $300 million RCF, which includes an option to expand the size to $400 million, upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. The amended facility extends the maturity from September 2016 to January 2019. In addition, we may extend the January 2019 maturity, subject to lenders' approval, by two additional one year periods. The terms of the agreement provide that amounts we borrow under the RCF may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by RGRT was $124.4 million at December 31, 2013, of which $14.4 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Borrowings by RGRT for nuclear fuel were $132.2 million at December 31, 2012, of which $22.2 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. No borrowings were outstanding at December 31, 2013 or December 31, 2012, under the RCF for working capital and general corporate purposes.

We believe we have adequate liquidity through our current cash balances, cash from operations, our RCF, and our favorable access to capital markets to meet all of our anticipated cash requirements for the next twelve months. In the fourth quarter of 2013, we received approval from the NMPRC and the FERC to incrementally issue up to $300 million of long-term debt and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides us with the flexibility to access the debt capital markets when needed and when conditions are favorable. We may decide to access the capital markets in the second half of 2014.

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Contractual Obligations. Our contractual obligations as of December 31, 2013 are as follows (in thousands):



	Payments due by period
	Total		2014		2015 and 2016		2017 and 2018		2019 and Beyond
Long-Term Debt (including interest):
Senior notes (1)	$	1,536,175	$	40,200	$	80,400	$	80,400	$	1,335,175
Pollution control bonds (2)	466,003		10,583		21,167		53,634		380,619
RGRT Senior notes (3)	135,918		5,054		24,557		56,771		49,536
Financing Obligations (including interest):
Revolving credit facility (4)	14,555		14,555		—		—		—
Purchase Obligations:
Power contracts	1,152		1,152		—		—		—
Fuel contracts:
Coal (5)	28,902		10,949		17,953		—		—
Gas (5)	374,650		47,865		83,233		75,079		168,473
Nuclear fuel (6)	105,323		21,930		32,961		29,762		20,670
Retirement Plans and Other Postretirement benefits (7)	13,870		13,870		—		—		—
Decommissioning trust funds (8)	152,637		4,535		9,071		9,071		129,960
Operating leases (9)	10,514		1,081		1,628		850		6,955
Total	$	2,839,699	$	171,774	$	270,970	$	305,567	$	2,091,388

_____________________


(1)	We have three issuances of Senior Notes. In May 2005, we issued $400.0 million in aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million in aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million in aggregate principal amount of 3.3% Senior Notes due December 15, 2022.


(2)	We have four series of pollution control bonds which are scheduled for remarketing and/or mandatory tender, one in 2017, two in 2040, and one in 2042.

(3)

In 2010, the Company and RGRT entered into a Note Purchase Agreement for $110 million aggregate principal amount of senior notes consisting of: (a) $15 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, due August 15, 2015, (b) $50 million aggregate principal amount of 4.47% RGRT Senior Notes, Series B, due August 15, 2017 and (c) $45 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020.


(4)	This reflects obligations outstanding under the $300 million RCF. At December 31, 2013, $14.4 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2013 and assumes this amount will be outstanding for the entire year of 2014.


(5)	Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2013. Gas obligation includes a gas storage contract and a gas transportation contract.


(6)	Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the index at the end of 2013.

(7)

This obligation is based on our expected contributions and includes our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2014. We have no minimum cash contractual funding requirement related to our retirement income plan or other postretirement benefits for 2014. However, we may decide to fund at higher levels and expect to contribute $13.9 million to our retirement plans in 2014, as disclosed in Part II, Item 8, Notes to Financial Statements, Note M, Employee Benefits. Minimum funding requirements for 2015 and beyond are not included due to the uncertainty of interest rates and the related return on assets.


(8)	These obligations represent funding amounts approved in PUCT Docket No. 40094 and NMPRC Case No. 09-00171-UT.


(9)	We lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, we lease certain warehouse facilities in El Paso under a lease which expires in December 2015. We also have several other leases for office, parking facilities and equipment which expire within the next four years.

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Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

The following discussion regarding our market-risk sensitive instruments contains forward-looking information involving risks and uncertainties. The statements regarding potential gains and losses are only estimates of what could occur in the future. Actual future results may differ materially from those estimates presented due to the characteristics of the risks and uncertainties involved.

We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial instruments and positions we hold are for purposes other than trading and are described below.

Interest Rate Risk

Our long-term debt obligations are all fixed-rate obligations, except for the RCF, which is based on floating rates.

To the extent the RCF is utilized for nuclear fuel purchases, interest rate risk, if any, related to the RCF is substantially mitigated through the operation of the PUCT and the NMPRC rules which establish energy cost recovery clauses. Under these rules, actual energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $85.3 million and $90.6 million as of December 31, 2013 and 2012, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.2 million and $0.7 million based on their fair values at December 31, 2013 and 2012, respectively.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $122.9 million and $92.0 million at December 31, 2013 and 2012, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $24.6 million and $18.4 million based on their fair values at December 31, 2013 and 2012, respectively. Declines in market prices could require that additional amounts be contributed to our decommissioning trusts to maintain minimum funding requirements. We will not have a requirement to expend monies held in trust before 2044 or a later period when we begin to decommission Palo Verde.

Commodity Price Risk

We utilize contracts of various durations for the purchase of natural gas, uranium concentrates and coal to effectively manage our available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand. However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the PUCT and NMPRC rules and our fuel clauses, as discussed previously.

In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2014, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, "Business – Energy Sources – Purchased Power." These agreements are generally fixed-priced contracts which qualify for the "normal purchases and normal sales" exception provided in FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

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Management Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and affected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;


•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and


•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013. In making this assessment, the Company’s management used the criteria set forth by the 1992 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2013, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s internal control over financial reporting. This report appears on page 45 of this report.

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Item 8.Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	45

Balance Sheets as of December 31, 2013 and 2012	46

Statements of Operations for the years ended December 31, 2013, 2012 and 2011	48

Statements of Comprehensive Operations for the years ended December 31, 2013, 2012 and 2011	49

Statements of Changes in Common Stock Equity for the years ended December 31, 2013, 2012 and 2011	50

Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	51

Notes to Financial Statements	52

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have audited the accompanying balance sheets of El Paso Electric Company as of December 31, 2013 and 2012, and the related statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2013. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Houston, Texas

February 26, 2014

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS



ASSETS (In thousands)	December 31,
	2013			2012
Utility plant:
Electric plant in service	$	3,076,549		$	2,857,913
Less accumulated depreciation and amortization	(1,214,088		)	(1,162,483		)
Net plant in service	1,862,461			1,695,430
Construction work in progress	282,647			287,358
Nuclear fuel; includes fuel in process of $48,492 and $56,129, respectively	188,185			189,921
Less accumulated amortization	(75,820		)	(70,366		)
Net nuclear fuel	112,365			119,555
Net utility plant	2,257,473			2,102,343
Current assets:
Cash and cash equivalents	25,592			111,057
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,261 and $2,906, respectively	65,350			62,900
Accumulated deferred income taxes	26,965			20,292
Inventories, at cost	45,942			42,358
Undercollection of fuel revenues	7,248			—
Prepayments and other	7,694			9,627
Total current assets	178,791			246,234
Deferred charges and other assets:
Decommissioning trust funds	214,095			187,053
Regulatory assets	101,050			101,590
Other	34,879			31,830
Total deferred charges and other assets	350,024			320,473
Total assets	$	2,786,288		$	2,669,050

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)



CAPITALIZATION AND LIABILITIES (In thousands except for share data)	December 31,
	2013			2012
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,639,091 and 65,520,551 shares issued, and 120,534 and 84,446 restricted shares, respectively	$	65,760		$	65,605
Capital in excess of stated value	314,443			310,994
Retained earnings	985,665			939,131
Accumulated other comprehensive income (loss), net of tax	2,612			(66,084		)
	1,368,480			1,249,646
Treasury stock, 25,492,919 shares at cost	(424,647		)	(424,647		)
Common stock equity	943,833			824,999
Long-term debt	999,620			999,535
Total capitalization	1,943,453			1,824,534
Current liabilities:
Short-term borrowings under the revolving credit facility	14,352			22,155
Accounts payable, principally trade	61,795			61,581
Taxes accrued	25,206			29,248
Interest accrued	12,189			12,127
Overcollection of fuel revenues	1,048			4,643
Other	22,932			21,995
Total current liabilities	137,522			151,749
Deferred credits and other liabilities:
Accumulated deferred income taxes	449,925			358,674
Accrued pension liability	84,012			125,690
Accrued postretirement benefit liability	50,655			99,170
Asset retirement obligation	65,214			62,784
Regulatory liabilities	26,416			22,179
Other	29,091			24,270
Total deferred credits and other liabilities	705,313			692,767
Commitments and contingencies
Total capitalization and liabilities	$	2,786,288		$	2,669,050

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(In thousands except for share data)



	Years Ended December 31,
	2013			2012			2011
Operating revenues	$	890,362		$	852,881		$	918,013
Energy expenses:
Fuel	226,768			191,076			223,507
Purchased and interchanged power	62,363			60,251			75,149
	289,131			251,327			298,656
Operating revenues net of energy expenses	601,231			601,554			619,357
Other operating expenses:
Other operations	237,155			236,558			229,570
Maintenance	61,068			60,339			62,092
Depreciation and amortization	79,626			78,556			81,331
Taxes other than income taxes	57,747			57,443			55,561
	435,596			432,896			428,554
Operating income	165,635			168,658			190,803
Other income (deductions):
Allowance for equity funds used during construction	10,008			9,427			8,161
Investment and interest income, net	7,033			5,275			5,664
Miscellaneous non-operating income	909			1,415			885
Miscellaneous non-operating deductions	(3,635		)	(2,013		)	(3,187		)
	14,315			14,104			11,523
Interest charges (credits):
Interest on long-term debt and revolving credit facility	58,635			54,632			54,115
Other interest	431			1,190			989
Capitalized interest	(5,299		)	(5,312		)	(5,177		)
Allowance for borrowed funds used during construction	(6,055		)	(5,573		)	(4,848		)
	47,712			44,937			45,079
Income before income taxes	132,238			137,825			157,247
Income tax expense	43,655			46,979			53,708
Net income	$	88,583		$	90,846		$	103,539

Basic earnings per share	$	2.20		$	2.27		$	2.49

Diluted earnings per share	$	2.20		$	2.26		$	2.48

Dividends declared per share of common stock	$	1.045		$	0.97		$	0.66
Weighted average number of shares outstanding	40,114,594			39,974,022			41,349,883
Weighted average number of shares and dilutive potential shares outstanding	40,126,647			40,055,581			41,587,059

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)



	Years Ended December 31,
	2013			2012			2011
Net income	$	88,583		$	90,846		$	103,539
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net gain (loss) arising during period	82,964			(2,109		)	(77,678		)
Prior service benefit	97			—			—
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(5,560		)	(5,762		)	(5,812		)
Net loss	10,472			11,971			6,505
Net unrealized gains/losses on marketable securities:
Net holding gains arising during period	17,699			9,927			1,570
Reclassification adjustments for net (gains) losses included in net income	(553		)	1,042			1,358
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	411			385			361
Total other comprehensive income (loss) before income taxes	105,530			15,454			(73,696		)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	(33,566		)	(1,464		)	30,134
Net unrealized gains on marketable securities	(3,100		)	(2,438		)	(563		)
Losses on cash flow hedges	(168		)	(131		)	(203		)
Total income tax benefit (expense)	(36,834		)	(4,033		)	29,368
Other comprehensive income (loss), net of tax	68,696			11,421			(44,328		)
Comprehensive income	$	157,279		$	102,267		$	59,211

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(In thousands except for share data)



	Common Stock					Capital in Excess of Stated Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss), Net of Tax			Treasury Stock				Common Stock Equity

	Shares		Amount												Shares	Amount
Balances at December 31, 2010	65,265,060		$	65,265		$	305,068		$	810,858		$	(33,177	)	22,693,995	$	(337,639	)	$	810,375
Restricted common stock grants and deferred compensation	118,110		118			3,087													3,205
Performance share awards vested	40,895		41			587													628
Stock awards withheld for taxes	(23,702	)	(24		)	(715		)											(739		)
Forfeited restricted common stock	(2,200	)	(2		)														(2		)
Deferred taxes on stock incentive plan						1,112													1,112
Stock options exercised	53,910		54			638													692
Net income									103,539										103,539
Other comprehensive loss												(44,328		)					(44,328		)
Dividends declared									(27,223		)								(27,223		)
Treasury stock acquired, at cost															2,798,924	(87,008		)	(87,008		)
Balances at December 31, 2011	65,452,073		65,452			309,777			887,174			(77,505		)	25,492,919	(424,647		)	760,251
Restricted common stock grants and deferred compensation	87,428		87			1,691													1,778
Performance share awards vested	174,038		174			1,019													1,193
Stock awards withheld for taxes	(52,778	)	(52		)	(1,770		)											(1,822		)
Forfeited restricted common stock	(88,100	)	(88		)	(1,206		)											(1,294		)
Deferred taxes on stock incentive plan						1,101													1,101
Stock options exercised	32,336		32			382													414
Net income									90,846										90,846
Other comprehensive income												11,421							11,421
Dividends declared									(38,889		)								(38,889		)
Balances at December 31, 2012	65,604,997		65,605			310,994			939,131			(66,084		)	25,492,919	(424,647		)	824,999
Restricted common stock grants and deferred compensation	96,279		96			2,702													2,798
Performance share awards vested	64,275		64			785													849
Stock awards withheld for taxes	(23,808	)	(23		)	(788		)											(811		)
Forfeited restricted common stock	(1,549	)	(1		)														(1		)
Deferred taxes on stock incentive plan						427													427
Stock options exercised	15,000		15			177													192
Compensation paid in shares	4,431		4			146													150
Net income									88,583										88,583
Other comprehensive income												68,696							68,696
Dividends declared									(42,049		)								(42,049		)
Balances at December 31, 2013	65,759,625		$	65,760		$	314,443		$	985,665		$	2,612		25,492,919	$	(424,647	)	$	943,833

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2013			2012			2011
Cash Flows From Operating Activities:
Net income	$	88,583		$	90,846		$	103,539
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	79,626			78,556			81,331
Amortization of nuclear fuel	42,537			42,953			37,018
Deferred income taxes, net	44,678			43,561			45,688
Allowance for equity funds used during construction	(10,008		)	(9,427		)	(8,161		)
Other amortization and accretion	16,556			14,724			19,875
Other operating activities	(925		)	(479		)	1,036
Change in:
Accounts receivable	(2,450		)	13,448			(4,663		)
Inventories	(3,673		)	(1,926		)	(3,750		)
Net overcollection (undercollection) of fuel revenues	(10,843		)	11,668			(26,001		)
Prepayments and other	(4,295		)	(2,784		)	(2,538		)
Accounts payable	8,180			1,725			4,401
Taxes accrued	(627		)	(3,054		)	11,915
Other current liabilities	958			78			(2,262		)
Deferred charges and credits	(822		)	(6,781		)	(5,911		)
Net cash provided by operating activities	247,475			273,108			251,517
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(237,411		)	(202,387		)	(178,041		)
Cash additions to nuclear fuel	(30,535		)	(46,009		)	(39,551		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(16,063		)	(15,000		)	(13,009		)
Nuclear fuel	(5,299		)	(5,312		)	(5,177		)
Allowance for equity funds used during construction	10,008			9,427			8,161
Decommissioning trust funds:
Purchases, including funding of $4.5 million, $4.5 million and $8.3 million, respectively	(65,491		)	(107,705		)	(95,441		)
Sales and maturities	56,148			98,542			82,926
Proceeds from sale of investments in debt securities	—			—			2,000
Other investing activities	5,879			2,390			727
Net cash used for investing activities	(282,764		)	(266,054		)	(237,405		)
Cash Flows From Financing Activities:
Repurchases of common stock	—			—			(86,508		)
Dividends paid	(42,049		)	(38,889		)	(27,223		)
Borrowings under the revolving credit facility:
Proceeds	44,883			234,575			120,450
Payments	(52,686		)	(245,799		)	(91,775		)
Pollution control bonds:
Proceeds	—			92,535			—
Payments	—			(92,535		)	—
Proceeds from issuance of senior notes	—			149,682			—
Other financing activities	(324		)	(3,774		)	(32		)
Net cash provided by (used for) financing activities	(50,176		)	95,795			(85,088		)
Net increase (decrease) in cash and cash equivalents	(85,465		)	102,849			(70,976		)
Cash and cash equivalents at beginning of period	111,057			8,208			79,184
Cash and cash equivalents at end of period	$	25,592		$	111,057		$	8,208

See accompanying notes to financial statements.

Table of Contents

INDEX TO NOTES TO FINANCIAL STATEMENTS



	Page
Note A. Summary of Significant Accounting Policies	53

Note B. New Accounting Standards	56

Note C. Regulation	56

Note D. Regulatory Assets and Liabilities	60

Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	61

Note F. Accounting for Asset Retirement Obligations	64

Note G. Common Stock	65

Note H. Accumulated Other Comprehensive Loss	70

Note I. Long-Term Debt and Financing Obligations	72

Note J. Income Taxes	74

Note K. Commitments, Contingencies and Uncertainties	76

Note L. Litigation	79

Note M. Employee Benefits	80

Note N. Franchises and Significant Customers	90

Note O. Financial Instruments and Investments	91

Note P. Supplemental Statements of Cash Flow Disclosures	95

Note Q. Selected Quarterly Financial Data (Unaudited)	96

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. El Paso Electric Company also serves a full requirements wholesale customer in Texas.

Dissolution of Subsidiary. MiraSol Energy Services, Inc. ("MiraSol"), the Company’s wholly owned subsidiary, provided energy efficiency products and discontinued these activities in 2002. MiraSol has had no material effect on the Company’s previously reported consolidated financial statements for the years ended December 31, 2012 and December 31, 2011. The Company dissolved MiraSol in the fourth quarter of 2013. MiraSol’s net assets and stockholders’ equity totaled less than $0.1 million and the dissolution of MiraSol had no material effect on the Company’s financial statements for the twelve months ended December 31, 2013.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the "FERC").

Application of FASB Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the Financial Accounting Standards Board ("FASB") guidance for regulated operations. FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income and ABFUDC is shown as capitalized interest charges in the Company’s statement of operations. FASB guidance for regulated operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Note D. The Company applies FASB guidance for regulated operations for all three of the jurisdictions in which it operates.

Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported as other comprehensive income in accordance with FASB guidance for reporting comprehensive income.

Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2013, 2012 and 2011 was 2.61%, 2.64%, and 2.80%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on the funding requirements of the Department of Energy (the "DOE") for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note E.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

AFUDC and Capitalized Interest. The Company capitalizes interest ("ABFUDC") and common equity ("AEFUDC") costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a semi-annual basis. The AFUDC rates used in 2013, 2012 and 2011 were 8.10%, 8.53% and 8.54%, respectively.

Asset Retirement Obligation. FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An asset retirement obligation ("ARO") associated with long-lived assets included within the scope of FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See Note F. Under FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense).

Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.

Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock equity. However, if declines in fair value of marketable securities below original cost basis are determined to be other than temporary, then the declines are reported as losses in the statement of operations and a new cost basis is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis. See Note O.

Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Note O.

Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost not to exceed recoverable cost.

Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the Public Utility Commission of Texas ("PUCT"). The Company’s New Mexico retail customers and its sales for resale customer are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Public Regulation Commission ("NMPRC") and the FERC. The Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/undercollection of fuel revenues in the balance sheets. See Note C.

Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $19.8 million and $17.9 million at December 31, 2013 and 2012, respectively. The Company presents revenues net of sales taxes in its statements of operations.

Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2013, 2012 and 2011 are as follows (in thousands):

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



	2013		2012		2011
Balance at beginning of year	$	2,906	$	3,015	$	2,885
Additions:
Charged to costs and expense	2,098		3,087		6,209
Recovery of previous write-offs	1,929		2,041		2,034
Uncollectible receivables written off	4,672		5,237		8,113
Balance at end of year	$	2,261	$	2,906	$	3,015

Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. FASB guidance requires that rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of FASB guidance for uncertainty in income taxes. See Note J.

Earnings per Share. The Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares and outstanding stock options. Net income allocated to the weighted average number of shares and dilutive potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the diluted earnings per share. See Note G.

Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (the "requisite service period") which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Note G.

Pension and Postretirement Benefit Accounting. See Note M for a discussion of the Company’s accounting policies for its employee benefits.

Reclassification. Certain amounts in the financial statements for 2012 and 2011 have been reclassified to conform with the 2013 presentation.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

B. New Accounting Standards

In February 2013, the FASB issued new guidance (Accounting Standards Update ("ASU") 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts.

Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement to present information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income now requires the presentation in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote disclosures. ASU 2013-02 became effective prospectively for reporting periods beginning after December 15, 2012. The Company implemented ASU 2013-02 in the first quarter of 2013 and has presented the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) with cross-references to other disclosures or the respective line items in net income in Note H.

In July 2013, the FASB issued new guidance (ASU 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. ASU 2013-11 is effective prospectively for all unrecognized tax benefits that exist for reporting periods beginning after December 15, 2013 and early adoption is permitted. Retrospective application is also permitted. The Company anticipates implementing ASU 2013-11 in the first quarter of 2014.The Company is currently assessing the future impact of this ASU, however it is not expected to have a significant impact on the Company's statement of operations or statements of cash flows.

C. Regulation

General

Texas Regulatory Matters

Under the terms of the settlement, among other things, the Company agreed to:


•	A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012;

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS


•	Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually;


•	Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and


•A	two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings.

Docket

No.

Date Filed

Date Approved

Recovery Period

Refund Period

Refund

Amount Authorized (In Thousands)

40622

August 3, 2012

September 28, 2012

January 2011- June 2012

September 2012

6,600

The Company filed the following petitions with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:



Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor	Effective Billing Month
40302	April 12, 2012	April 25, 2012	(18.5)%	May 2012
41803	September 9, 2013	September 23, 2013	12.2%	October 2013

Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") authorization from the PUCT to construct the first two (of four) units of the Montana Power Station ("the MPS"). The Company must also obtain air permits from state and federal regulatory agencies before it can begin construction. On January 22, 2014, the Texas Commission on Environmental Quality ("TCEQ") issued the required permit. The U.S. Environmental Protection Agency ("EPA") issued a draft permit for greenhouse gas ("GHG") in September 2013 and solicited public comment. EPA is considering comments filed in response to that proposal before issuing a final permit. The Company believes that the type of facility planned

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

at the MPS complies with all EPA regulations for granting a GHG permit and that the issues raised in the comments have previously been resolved in proceedings in other regions in favor of the grant of a permit. If the permit is granted, commenters may challenge the determination before the U.S. EPA’s Environmental Appeals Board. While the Company believes that this application demonstrates compliance with all applicable regulations, it cannot predict the timing or final outcome.

On September 6, 2013, the Company filed an application with the PUCT for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case has been designated PUCT Docket No. 41763. Hearings in this case were held in February 2014. In accordance with PUCT rules, the final order must be issued by September 5, 2014.

The Company filed three transmission line CCN applications with the PUCT as part of the MPS Project:


•	MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360)


•	MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359)


•	MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809)

New Mexico Regulatory Matters

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On October 30, 2013, the Company received approval in NMPRC Case No. 13-00317-UT to amend its current $300 million Revolving Credit Facility ("RCF") to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the financing of purchases of nuclear fuel.

Federal Regulatory Matters

Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.

Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comision Federal de Electricidad in Mexico pursuant to a license granted by the DOE and a presidential permit.

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Note E for discussion of spent fuel storage and disposal costs.

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Sales for Resale

D. Regulatory Assets and Liabilities

The Company's operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Company's balance sheets are presented below (in thousands):



	Amortization Period Ends	December 31, 2013		December 31, 2012
Regulatory assets
Regulatory tax assets (a)	(b)	$	61,772	$	57,551
Loss on reacquired debt (c)	May 2035	18,338		19,191
Final coal reclamation (f)	July 2016	4,290		5,473
Nuclear fuel postload daily financing charge	(d)	4,141		3,833
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	893		926
Texas energy efficiency	(e)	—		536
Texas 2012 rate case costs (f)	April 2014	581		2,335
Texas military base discount and recovery factor	(h)	759		2,116
New Mexico procurement plan costs	(g)	139		139
New Mexico renewable energy credits	(g)	4,833		4,033
New Mexico 2010 FPPCAC audit	(g)	433		433
New Mexico Palo Verde deferred depreciation	(b)	4,871		5,024
Total regulatory assets		$	101,050	$	101,590
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	17,752	$	16,666
Accumulated deferred investment tax credit (i)	(b)	4,656		4,587
New Mexico energy efficiency	(e)	3,646		926
Texas energy efficiency	(e)	362		—
Total regulatory liabilities		$	26,416	$	22,179

________________


(a)	No specific return on investment is required since related assets and liabilities offset.


(b)	The amortization period for this asset is based upon the life of the associated assets or liabilities.


(c)	This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.


(d)	This item is recovered through fuel recovery mechanisms.


(e)	This item is recovered or credited through a recovery factor that is set annually.


(f)	This item is included in rate base which earns a return on investment.


(g)	Amortization period is anticipated to be established in next general rate case.


(h)	This item represents the net asset related to the military discount which is recovered from non-military customers through a recovery factor.


(i)	This item is excluded from rate base.

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E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant

The table below presents the balance of each major class of depreciable assets at December 31, 2013 (in thousands):



	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	817,665	$	(271,173	)	$	546,492
Steam and other	668,666		(264,019		)	404,647
Total production	1,486,331		(535,192		)	951,139
Transmission	432,674		(246,175		)	186,499
Distribution	965,674		(337,513		)	628,161
General	122,209		(58,231		)	63,978
Intangible	69,661		(36,977		)	32,684
Total	$	3,076,549	$	(1,214,088	)	$	1,862,461

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 5 to 10 years). The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and for the next five years (in thousands):




2011	$	6,668
2012	7,183
2013	7,683
2014 (estimated)	7,372
2015 (estimated)	6,540
2016 (estimated)	5,980
2017 (estimated)	5,326
2018 (estimated)	3,713

The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: Arizona Public Service Company ("APS"), Southern California Edison Company ("SCE"), Public Service Company of New Mexico ("PNM"), Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District ("SRP") and the Los Angeles Department of Water and Power.

Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners") and certain other transmission facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2013 and 2012 is as follows (in thousands):



	December 31, 2013						December 31, 2012
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	817,665		$	217,137		$	795,259		$	213,155
Accumulated depreciation	(271,173		)	(173,819		)	(257,540		)	(168,569		)
Construction work in progress	75,040			2,347			64,623			2,401
Total	$	621,532		$	45,665		$	602,342		$	46,987

Palo Verde

The operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the "ANPP Participation Agreement"). APS serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde.

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Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s statements of operations. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential amount of future payment, if any, which could be required under this provision.

NRC. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee’s safety performance.

License Extension. On April 21, 2011, the Company, along with the other Palo Verde Participants, was notified that the NRC had renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively.

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2013, the Company’s decommissioning trust fund had a balance of $214.1 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjust its deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In December 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"). The 2013 Study estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $23.3 million (stated in 2013 dollars) from the 2010 Palo Verde decommissioning study. However, because the cash flows from the 2013 Study were less than the inflated amounts from the 2010 Study, the effect of this change lowered the asset retirement obligation by $1.9 million and will lower annual expenses starting in January 2014. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty.

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE's breach of the spent nuclear fuel contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.0 million in damages to the Palo Verde participants for costs incurred through December 2006. In October 2010, the Company received $4.8 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.The lawsuit is presently pending in the Court of Federal Claims.

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D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds. The Company cannot predict when spent fuel shipments to the DOE will commence.

The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh fee (the "one-mill fee") paid by the nation’s commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract. This fee is recovered by the Company through applicable fuel adjustment clauses. In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit") held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE ("Secretary") with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the court’s order. On January 3, 2014, the Secretary notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval.

Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law, which is currently at $13.6 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $375 million, and the balance is covered by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $127.3 million, subject to an annual limit of $19.0 million. Based upon the Company's 15.8% interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $60.4 million, with an annual payment limitation of approximately $9.0 million.

The Palo Verde Participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $9.8 million for the current policy period.

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NOTES TO FINANCIAL STATEMENTS

Four Corners

The Company owns a 7% interest in Units 4 and 5 at Four Corners. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. The 50-year participation agreement among the owners of Four Corners expires by its terms in July 2016. The Company has notified the other owners that it has decided to cease its participation in the plant by July 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation. The Company has nevertheless agreed to work with the other owners and the Navajo Nation in an attempt to facilitate their efforts to extend the operation of the plant beyond July 2016 in a manner consistent with protecting the Company's ratepayers. In December 2013, the other owners executed a long-term extension of the coal supply agreement for the plant through 2031. The Company did not sign the extension and APS has agreed to assume the resulting 7% shortfall and has also expressed an interest in acquiring the Company’s interest in Four Corners.

F. Accounting for Asset Retirement Obligations

The Company complies with FASB guidance for asset retirement obligations ("ARO"). This guidance affects the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and the method used to report the decommissioning obligation. The Company also complies with FASB guidance for conditional asset retirement obligations which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s AROs are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The 2013 ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2013 Palo Verde decommissioning study. See Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company maintains six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2013 is $214.1 million.

FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. In December 2013, the Company implemented the 2013 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to decrease its estimated cash flows from the 2010 Study to the 2013 Study (see Note E). The assumptions used to calculate the Palo Verde ARO liability are as follows:



	Escalation Rate		Credit-Risk Adjusted Discount Rate
Original ARO liability	3.60	%	9.50	%
Incremental ARO liability	3.60	%	6.20	%

A roll forward of the Company’s total ARO liability from January 1, 2011 through December 31, 2013, including the effects of each year’s estimate revisions, is presented below. In 2013, the estimate revision includes a change to the probability of extending Four Corners’ operating term and decreases in the estimated cash flows related to Palo Verde’s decommissioning due to implementing the 2013 Palo Verde decommissioning study. In 2012, the estimate revision includes a change to the probability of

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

extending Four Corners’ operating term. In 2011, the NRC approved the Palo Verde license extension which increased Palo Verde decommissioning estimated cash flows and the related probabilities for life extension in the Company’s ARO calculation.



	2013			2012			2011
ARO liability at beginning of year	$	62,784		$	56,140		$	92,911
Liabilities incurred	—			—			—
Liabilities settled	(36		)	(450		)	(793		)
Revisions to estimate	(3,401		)	1,929			(41,670		)
Accretion expense	5,867			5,165			5,692
ARO liability at end of year	$	65,214		$	62,784		$	56,140

The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises.

G. Common Stock

Overview

The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.

Long-Term Incentive Plan

On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the "2007 LTIP") and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the 2007 LTIP, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of the 2007 LTIP. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation.

Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options expired ten years from the date of grant unless terminated earlier by the Board of Directors (the “Board”). Stock options have not been granted since 2003.

The 15,000 options outstanding at December 31, 2012 were exercised during 2013 with a weighted average exercise price of $12.78. The Company received $0.2 million in cash and realized a current tax benefit of $0.1 million. The Company has no stock options outstanding as of December 31, 2013.

The intrinsic value of stock options exercised in 2013, 2012 and 2011 were $0.3 million, $0.6 million and $1.0 million, respectively. No options were forfeited, vested or expired during 2013, 2012 and 2011. No compensation cost was recognized in 2013, 2012 and 2011 for stock options.

Restricted Stock. The Company has awarded restricted stock under its long-term incentive plan. Restrictions from resale generally lapse and awards vest over periods of one to three years. The market value of the unvested restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures.

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NOTES TO FINANCIAL STATEMENTS

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock awards in 2013, 2012 and 2011 is presented below (in thousands):



	2013		2012		2011

Expense (a)	$	2,458	$	1,508	$	2,258
Deferred tax benefit	860		528		790
Current tax benefit recognized	109		94		518

_____________________

(a) Any capitalized costs related to these expenses is less than $0.1 million for all years.

The aggregate intrinsic value and fair value at grant date of restricted stock which vested in 2013, 2012 and 2011 is presented below (in thousands):



	2013		2012		2011

Aggregated intrinsic value	$	2,077	$	2,242	$	3,279
Fair value at grant date	1,765		1,973		1,799

The unvested restricted stock transactions for 2013 are presented below:



	Total Shares		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Restricted shares outstanding at December 31, 2012	84,446		$	31.26
Restricted stock awards	96,279		35.48
Vested	(58,642	)	30.10
Forfeitures	(1,549	)	31.28
Restricted shares outstanding at December 31, 2013	120,534		35.19		$	1,976	$	4,232

_______________________

(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year.

The weighted average fair value per share at grant date for restricted stock awarded during 2013, 2012 and 2011 were:



	2013		2012		2011
Weighted average fair value per share	$	35.48	$	32.45	$	28.98

The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and receive cash dividends on restricted stock.

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NOTES TO FINANCIAL STATEMENTS

Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plan, which provides for issuance of Company stock based on the achievement of certain performance criteria over a three-year period. The payout varies between 0% to 200% of performance share awards.

Detail of performance shares vested follows:



Date Vested	Payout Ratio		Performance Shares Awarded	Compensation Costs Expensed		Period Compensation Costs Expensed	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
February 18, 2014	0	%	0	$	954	2011-2013	$	—
January 29, 2013	150.0	%	64,275	849		2010-2012	2,176
January 1, 2012	175.0	%	174,038	1,193		2009-2011	6,029
September 3, 2011	112.5	%	3,825	40		2008-2011	129
July 9, 2011	112.5	%	2,250	23		2008-2011	75

In 2014, 2015 and 2016, subject to meeting certain performance criteria, additional performance shares could be awarded. In accordance with FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. The actual number of shares to be issued can range from zero to 181,894 shares.

The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation. The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the plan’s term structure and includes the volatilities of all members of the defined peer group.

The outstanding performance share awards at the 100% performance level is summarized below:



	Number Outstanding		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Performance shares outstanding at December 31, 2012	128,033		$	26.48
Performance share awards	39,814		34.69
Performance shares vested	(42,850	)	19.82
Performance shares outstanding at December 31, 2013	124,997		31.38		$	1,452	$	4,389

_______________________

(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year.

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NOTES TO FINANCIAL STATEMENTS

A summary of information related to performance shares for 2013, 2012 and 2011 is presented below:



	2013		2012		2011
Weighted average per share grant date fair value per share of performance shares awarded	$	34.69	$	32.74	$	23.45
Fair value of performance shares vested (in thousands)	849		1,193		628
Intrinsic value of performance shares vested (in thousands) (a)	1,450		3,464		1,032
Compensation expense (in thousands) (b)	1,188		170		1,573
Deferred tax benefit related to compensation expense (in thousands)	416		59		551

_____________________

(a) Based on a 100% performance level.

(b) Includes adjustments for forfeiture of performance share awards by certain executives.

Repurchase Program

No shares of common stock were repurchased during the twelve months ended December 31, 2013. Detail regarding the Company's stock repurchase program are presented below:

______________________


(a)	Represents repurchased shares and cost since inception of the stock repurchase program in 1999.


(b)	Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the Company's repurchase programs.

The Company may in the future make purchases of its common stock pursuant to its authorized program in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.

Dividend Policy

On December 30, 2013, the Company paid $10.7 million in quarterly cash dividends to shareholders. The Company paid a total of $42.0 million, $38.9 million and $27.2 million in cash dividends during the twelve months ended December 31, 2013, 2012 and 2011, respectively. On January 23, 2014, the Board of Directors declared a quarterly cash dividend of $0.265 per share payable on March 31, 2014 to shareholders of record on March 14, 2014.

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NOTES TO FINANCIAL STATEMENTS

Basic and Diluted Earnings Per Share

FASB guidance requires the Company to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock which qualifies as a participating security. The basic and diluted earnings per share are presented below:



	Years Ended December 31,
	2013			2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,114,594			39,974,022			41,349,883
Dilutive effect of unvested performance awards	12,053			66,756			206,658
Dilutive effect of stock options	—			14,803			30,518
Diluted number of common shares outstanding	40,126,647			40,055,581			41,587,059
Basic net income per common share:
Net income	$	88,583		$	90,846		$	103,539
Income allocated to participating restricted stock	(254		)	(256		)	(471		)
Net income available to common shareholders	$	88,329		$	90,590		$	103,068
Diluted net income per common share:
Net income	$	88,583		$	90,846		$	103,539
Income reallocated to participating restricted stock	(254		)	(256		)	(469		)
Net income available to common shareholders	$	88,329		$	90,590		$	103,070
Basic net income per common share:
Distributed earnings	$	1.045		$	0.97		$	0.66
Undistributed earnings	1.155			1.30			1.83
Basic net income per common share	$	2.200		$	2.27		$	2.49
Diluted net income per common share:
Distributed earnings	$	1.045		$	0.97		$	0.66
Undistributed earnings	1.155			1.29			1.82
Diluted net income per common share	$	2.200		$	2.26		$	2.48

The amount of restricted stock awards and performance shares at 100% performance level excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:



	Year Ended December 31,
	2013	2012	2011
Restricted stock awards	51,189	45,178	81,653
Performance shares (a)	115,044	57,625	—

_____________________


(a)	Certain performance shares were excluded from the computation of diluted earnings per share as no payouts would have been required based upon performance at the end of each corresponding period.

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NOTES TO FINANCIAL STATEMENTS

H. Accumulated Other Comprehensive Income (Loss)



Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component which are presented below (in thousands):
		Years Ended December 31, 2013
		Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2012		$	(75,737	)	$	22,194		$	(12,541	)	$	(66,084	)
	Other comprehensive income before reclassifications	51,371			14,482			—			65,853
	Amounts reclassified from accumulated other comprehensive income (loss)	3,036			(436		)	243			2,843
Balance at December 31, 2013		$	(21,330	)	$	36,240		$	(12,298	)	$	2,612

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Amounts reclassified from accumulated other comprehensive income (loss) for the twelve months ended December 31, 2013 are as follows ( in thousands):



Details about Accumulated Other Comprehensive Income (Loss) Components		2013			Affected Line Item in the Statement of Operations

Amortization of pension and postretirement benefit costs:
	Prior service benefit	$	5,560		(a)
	Net loss	(10,472		)	(a)
		(4,912		)	(a)
	Income tax effect	1,876
		(3,036		)	(a)

Marketable securities:
	Net realized gain on sale of securities	553			Investment and interest income, net
		553			Income before income taxes
		(117		)	Income tax expense
		436			Net income

Loss on cash flow hedge:
	Amortization of loss	(411		)	Interest on long-term debt and revolving credit facility
		(411		)	Income before income taxes
		168			Income tax expense
		(243		)	Net income

	Total reclassifications	$	(2,843	)

(a) These items are included in the computation of net periodic benefit cost. See Note M, Employee Benefits, for additional information.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

I. Long-Term Debt and Financing Obligations

Outstanding long-term debt and financing obligations are as follows:



	December 31,
	2013			2012
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (1):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	63,500		$	63,500
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	59,235			59,235
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	37,100			37,100
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)	33,300			33,300
Total Pollution Control Bonds	193,135			193,135
Senior Notes (2):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)	397,976			397,934
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,800			148,783
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	149,709			149,683
Total Senior Notes	696,485			696,400
RGRT Senior Notes (3):
3.67% Senior Notes, Series A, due 2015 (3.87% effective interest rate)	15,000			15,000
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	50,000			50,000
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	45,000			45,000
Total RGRT Senior Notes	110,000			110,000
Total long-term debt	999,620			999,535
Financing Obligations:
Revolving Credit Facility ($14,352 due in 2014) (4)	14,352			22,155
Total long-term debt and financing obligations	1,013,972			1,021,690
Current Portion (amount due within one year):
Short-term borrowings under the revolving credit facility	(14,352		)	(22,155		)
	$	999,620		$	999,535

_____________________


(1)	Pollution Control Bonds ("PCBs")

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017.


(2)	Senior Notes

The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions. The 6.00% senior notes have an aggregate principal amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% senior notes. See Note O, "Financial Instruments and Investments - Treasury Rate Locks". This amortization is included in the effective interest rate of the 6.00% senior notes.

The 7.50% senior notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds, net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for other general corporate purposes.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The 3.30% senior notes have an aggregate principal amount of $150.0 million and were issued in December 2012. The proceeds, net of a $0.3 million discount, were used to fund construction expenditures and for working capital and general corporate purposes.


(3)	RGRT Senior Notes

In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the Agreement, RGRT sold to the purchasers $110 million aggregate principal amount of senior notes (the "Notes"). The Company guarantees the payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of the RGRT are reported as assets and liabilities of the Company.

RGRT will pay interest on the Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The agreement requires compliance with certain

covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2013.

The sale of the Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act of 1933, as amended.

The proceeds of $109.4 million, net of issuance costs, from the sale of the Notes was used by RGRT to repay amounts borrowed under the revolving credit facility and will enable future nuclear fuel financing requirements of RGRT to be met with a combination of the Notes and amounts borrowed from the revolving credit facility.


(4)	Revolving Credit Facility

The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under the RCF is recorded as short-term borrowings on the balance sheet. The RCF is unsecured. The RCF requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2013. As of December 31, 2013, the total amount borrowed by RGRT was $14.4 million for nuclear fuel under the RCF. As of December 31, 2013, no borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 1.4% as of December 31, 2013.

As of December 31, 2013, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):




2014	$	—
2015	15,000
2016	—
2017	83,300
2018	—

The $14.4 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2014.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

J. Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2013 and 2012 are presented below (in thousands):



	December 31,
	2013			2012
Deferred tax assets:
Benefit of tax loss carryforwards	$	17,709		$	7,798
Alternative minimum tax credit carryforward	21,638			21,599
Pensions and benefits	54,652			86,816
Asset retirement obligation	23,727			21,710
Deferred fuel	—			1,951
Other	14,485			14,115
Total gross deferred tax assets	132,211			153,989
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(511,847		)	(457,127		)
Decommissioning	(35,489		)	(29,416		)
Deferred fuel	(2,171		)	—
Other	(5,664		)	(5,828		)
Total gross deferred tax liabilities	(555,171		)	(492,371		)
Net accumulated deferred income taxes	$	(422,960	)	$	(338,382	)

Based on the average annual book income before taxes for the prior three years, excluding the effects of extraordinary and unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized at current levels of book and taxable income.

The Company recognized income tax expense for 2013, 2012 and 2011 as follows (in thousands):



	Years Ended December 31,
	2013			2012			2011
Income tax expense:
Federal:
Current	$	(2,877	)	$	1,487		$	5,084
Deferred	45,024			43,187			46,864
Total federal income tax	42,147			44,674			51,948
State:
Current	1,854			1,931			2,936
Deferred	(414		)	697			(924		)
Total state income tax	1,440			2,628			2,012
Generation (amortization) of accumulated investment tax credits	68			(323		)	(252		)
Total income tax expense	$	43,655		$	46,979		$	53,708

As of December 31, 2013, the Company had $21.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2013, the Company had $17.3 million of federal and $0.4 million of state tax loss carryforwards. If unused, the tax loss carryforwards would expire at the end of 2031 through 2033 and 2016 through 2018, for federal and state, respectively.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book income before federal income tax as follows (in thousands):



	Years Ended December 31,
	2013			2012			2011
Federal income tax expense computed on income at statutory rate	$	46,283		$	48,239		$	55,036
Difference due to:
State taxes, net of federal benefit	936			1,708			1,308
AEFUDC	(2,149		)	(1,845		)	(2,295		)
Permanent tax differences	(1,153		)	(604		)	(303		)
Other	(262		)	(519		)	(38		)
Total income tax expense	$	43,655		$	46,979		$	53,708
Effective income tax rate	33.0		%	34.1		%	34.2		%

The Company files income tax returns in the United State ("U.S.") federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2009 and in New Mexico for years prior to 2009. The Company is currently under audit in Texas for tax years 2007 through 2011. A deficiency notice relating to the Company’s 1998 through 2003 and 2006 and 2007 income tax returns in Arizona challenges a pollution control credit, a research and development credit and the payroll, sales and property apportionment factors. The Company is contesting these adjustments.

FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In January 2010, the Company filed for a change of accounting method with the IRS related to the way in which units of property are determined for purposes of determining capitalized tax assets. The change was included in the 2009 federal income tax return, with additional amounts included in the 2010 to 2012 federal income tax returns. The Company recorded an additional unrecognized tax position of $1.6 million and $2.2 million in 2012 and 2011, respectively, related to the change in accounting method in 2009 through 2012. In 2013, a $4.5 million decrease was made to the reserve related to the change in accounting method. The decrease is primarily the result of the completion of IRS audits for tax years 2009 to 2012. Further changes to the unrecognized tax position may be recognized as the IRS releases additional guidance as it pertains to the repair allowance for generation assets. The Company recorded an unrecognized tax position of $0.5 million and $1.4 million in 2013 and 2012, respectively, related to depreciation amounts deducted in current and prior year Texas franchise tax returns. The Company recorded an unrecognized tax position of $1.3 million (net of a decrease of $0.4 million) in 2013 related to tax credits taken in prior year Arizona income tax returns. A reconciliation of the December 31, 2013, 2012 and 2011 amount of unrecognized tax benefits is as follows (in thousands):



	2013			2012			2011
Balance at January 1	$	9,800		$	9,500		$	7,300
Additions for tax positions related to the current year	600			1,600			2,200
Reductions for tax positions related to the current year	—			(900		)	—
Additions for tax positions of prior years	1,700			1,400			—
Reductions for tax positions of prior years	(4,900		)	(1,800		)	—
Balance at December 31	$	7,200		$	9,800		$	9,500

If recognized, $2.5 million of the unrecognized tax position at December 31, 2013, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $1.8 million for the year ended December 31, 2013.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the year ended December 31, 2012, the Company recognized a benefit of $0.3 million in interest. For both of the years ended December 31, 2013 and 2011, the Company recognized interest expense of $0.2 million. The Company had approximately $0.4 million and $0.1 million accrued for the payment of interest and penalties at December 31, 2013 and 2012, respectively.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

K. Commitments, Contingencies and Uncertainties

Power Purchase and Sale Contracts

To supplement its own generation and operating reserves and to meet required renewable portfolio standards, the Company engages in power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions, and specific renewable portfolio requirements. The Company had entered into the following significant agreements with various counterparties for forward purchases and sales of electricity:



						Commercial
						Operation
Type of Contract	Counterparty	Quantity			Term	Date
Power Purchase and Sale Agreement	Freeport		125	MW	December 2008 through December 2014	N/A
Power Purchase and Sale Agreement	Freeport		100	MW	January 2015 through December 2021	N/A
Power Purchase Agreement	Shell	Up to	40	MW	January 2011 through September 2014	N/A
Power Purchase Agreement	NRG		20	MW	August 2011 through August 2031	August 2011
Power Purchase Agreement	Sun Edison 1		10	MW	June 2012 through June 2037	June 2012
Power Purchase Agreement	Sun Edison 2		12	MW	May 2012 through May 2037	May 2012
Power Purchase Agreement	Hatch Solar Energy Center I, LLC		5	MW	July 2011 through June 2036	July 2011
Power Purchase Agreement	Macho Springs Solar, LLC		50	MW	20 years after operational start date	Expected May 1, 2014
Power Purchase Agreement	Newman Solar, LLC		10	MW	30 years after operational start date	Expected December 31, 2014

The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2014. The contract was approved by the FERC and continues through December 31, 2021.

The Company entered into an agreement in 2009 to purchase capacity and unit contingent energy during 2010 from Shell Energy North America ("Shell"). Under the agreement, the Company provides natural gas to Pyramid Unit No. 4 where Shell has the right to convert natural gas to electric energy. The Company entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014.

The Company entered into a 20-year contract with NRG Solar Roadrunner LLC ("NRG") for the purchase of all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchased power agreement with Hatch Solar Energy Center I, LLC for a solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements.

In May 2013, the NMPRC approved the Company's agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico. The term of the purchased power agreement is 20 years from the commercial operation date of the Macho Springs project which is projected to be May 1, 2014. In addition, on September 5, 2013, the Company entered into a purchased power agreement with Newman Solar LLC to purchase, for a term of 30 years, the total output from a solar photovoltaic generation facility of approximately 10 MW that Newman Solar LLC will construct, own and operate on land subleased from the Company in proximity to its Newman Power Station. This solar project is expected to be on line at the end of 2014.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Environmental Matters

Clean Air Interstate Rule/Cross State Air Pollution Rule. The EPA Clean Air Interstate Rule ("CAIR"), as applied to the Company since 2009, involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, on appeal the rule was reinstated until such time as the EPA promulgates a replacement rule. Because the appellate court in August 2012 also vacated the EPA’s proposed replacement, which is called the Cross-State Air Pollution Rule ("CSAPR"), CAIR remains in effect. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit's decision to vacate CSAPR. On June 24, 2013, the Supreme Court agreed to hear the case, and oral arguments were heard on December 10, 2013. The timing and outcome of the Supreme Court decision is unknown, and in the meantime, the Company remains subject to CAIR.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

third parties relating to water supply issues. The drought conditions and related negotiations and proceedings could adversely affect the amount of power available, or the price thereof, from Four Corners.

Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress periodically considers legislation to restrict or regulate GHG emissions. In the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which applied to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions, which may create significant costs for power plant owners and operators. On June 25, 2013, President Obama set forth his plan to address climate change. He reiterated a goal of reducing GHG "in the range of 17 percent" below 2005 levels by 2020. The plan included a variety of executive actions, including future regulatory measures to reduce carbon emissions from power plants. In a White House memorandum of the same date, the President directed the EPA to issue a new proposal for GHG rulemaking addressing new power plants by September 20, 2013, and a rule for existing power plants by June 1, 2014. The formal proposal for new power plants was published in the Federal Register on January 8, 2014. The Company continues its review of the new proposal and plans to participate in the 60-day post-publication comment period. Given the very significant remaining uncertainties regarding these rules, the Company believes it is impossible to meaningfully quantify the costs of these potential requirements at present.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS, the Company and the other Four Corners participants may reinstate the motions to dismiss. On February 14, 2014, the parties filed a joint motion to extend the stay in the case by 30 days holding the matter in abeyance until March 17, 2014. The Company is unable to predict the outcome of this litigation.

New Mexico Tax Matter Related to Coal Supplied to Four Corners

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). The Company's share of the assessment is approximately $1.5 million. On behalf of the Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. APS believes the Assessment and the refund claim denial are without merit. The Company cannot predict the timing, results, or potential impacts of the outcome of this litigation.

Lease Agreements

The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, the Company leases certain warehouse facilities in El Paso under a lease which expires in December 2015. The Company also has several other leases for office, parking facilities and equipment which expire within the next four years . These lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.

The Company's total annual rental expense related to operating leases was $1.2 million, $1.3 million, and $1.1 million for 2013, 2012 and 2011, respectively. As of December 31, 2013, the Company’s minimum future rental payments for the next five years are as follows (in thousands):



2014	$	1,081
2015	1,028
2016	600
2017	442
2018	408

Union Matters

The Company has approximately 1,000 employees, about 40% of whom are covered by a collective bargaining agreement. The International Brotherhood of Electrical Workers Local 960 ("Local 960") represents the Company’s employees working primarily in the power plants, substations, line crews, meter reading and collection, facilities services, and customer service. The Company entered into a new collective bargaining agreement effective September 3, 2013, with Local 960 for a three-year term ending September 2, 2016. The agreement provides for pay increases of 3% on September 3, 2013, 3% on September 3, 2014 and 2.25% on September 3, 2015.

L. Litigation

See Note C and Note K for discussion of the effects of government legislation and regulation on the Company.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

M. Employee Benefits

Retirement Plans

The Company’s Retirement Income Plan (the "Retirement Plan") covers employees who have completed one year of service with the Company and work at least a minimum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan. Retirement benefits are based on the employee's final average pay and years of service. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager appointed by the Company.

The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental Retirement Plan covers certain former employees and directors of the Company. The other plan, the Excess Benefit Plan was adopted in 2004 and covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan. The Company complies with FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk.

The obligations and funded status of the plans are presented below (in thousands):



	December 31,
	2013						2012
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	$	320,846		$	27,241		$	296,293		$	26,547
Service cost	9,137			190			8,530			299
Interest cost	12,742			872			12,594			963
Actuarial (gain) loss	(15,373		)	(533		)	12,417			1,338
Benefits paid	(9,537		)	(1,872		)	(8,988		)	(1,906		)
Benefit obligation at end of year	317,815			25,898			320,846			27,241
Change in plan assets:
Fair value of plan assets at end of prior year	220,568			—			191,369			—
Actual return on plan assets	31,800			—			20,187			—
Employer contribution	15,000			1,872			18,000			1,906
Benefits paid	(9,537		)	(1,872		)	(8,988		)	(1,906		)
Fair value of plan assets at end of year	257,831			—			220,568			—
Funded status at end of year	$	(59,984	)	$	(25,898	)	$	(100,278	)	$	(27,241	)

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Amounts recognized in the Company's balance sheets consist of the following (in thousands):



	December 31,
	2013						2012
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(1,870	)	$	—		$	(1,829	)
Noncurrent liabilities	(59,984		)	(24,028		)	(100,278		)	(25,412		)
Total	$	(59,984	)	$	(25,898	)	$	(100,278	)	$	(27,241	)

The accumulated benefit obligation in excess of plan assets is as follows (in thousands):



	December 31,
	2013						2012
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(317,815	)	$	(25,898	)	$	(320,846	)	$	(27,241	)
Accumulated benefit obligation	(275,555		)	(25,077		)	(274,890		)	(26,363		)
Fair value of plan assets	257,831			—			220,568			—

Amounts recognized in accumulated other comprehensive income consist of the following (in thousands):



	Years Ended December 31,
	2013				2012
	Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	85,261	$	8,508	$	125,763	$	9,701
Prior service cost	—		219		3		314
Total	$	85,261	$	8,727	$	125,766	$	10,015

The following are the weighted-average actuarial assumptions used to determine the benefit obligations:



	December 31,
	2013						2012
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.9	%	3.9	%	4.9	%	4.0	%	3.1	%	4.0	%
Rate of compensation increase	4.75	%	N/A		4.75	%	4.75	%	N/A		4.75	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2013 retirement plans' projected benefit obligation by 12.5%. A 1% decrease in the discount rate would increase the December 31, 2013 retirement plans' projected benefit obligation by 15.5%.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The components of net periodic benefit cost are presented below (in thousands):



	Years Ended December 31,
	2013					2012					2011
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	9,137		$	190	$	8,530		$	299	$	6,590		$	260
Interest cost	12,742			872		12,594			963		12,871			1,116
Expected return on plan assets	(17,108		)	—		(14,443		)	—		(14,095		)	—
Amortization of:
Net loss	10,437			661		10,729			627		6,190			354
Prior service cost	3			94		21			94		21			94
Net periodic benefit cost	$	15,211		$	1,817	$	17,431		$	1,983	$	11,577		$	1,824

The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2013						2012						2011
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	(30,065	)	$	(533	)	$	6,672		$	1,337		$	40,181		$	2,980
Amortization of:
Net loss	(10,437		)	(661		)	(10,729		)	(627		)	(6,190		)	(354		)
Prior service cost	(3		)	(94		)	(21		)	(94		)	(21		)	(94		)
Total recognized in other comprehensive income	$	(40,505	)	$	(1,288	)	$	(4,078	)	$	616		$	33,970		$	2,532

The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2013					2012				2011
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Total recognized in net periodic benefit cost and other comprehensive income	$	(25,294	)	$	529	$	13,353	$	2,599	$	45,547	$	4,356

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2014 (in thousands):



	Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	6,270	$	570
Prior service cost	—		90

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NOTES TO FINANCIAL STATEMENTS

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31:



	2013						2012						2011
			Non-Qualified						Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.0	%	3.1	%	4.0	%	4.3	%	3.6	%	4.1	%	5.4	%	4.6	%	5.3	%
Expected long-term return on plan assets	7.5	%	N/A		N/A		7.5	%	N/A		N/A		7.5	%	N/A		N/A
Rate of compensation increase	4.75	%	N/A		4.75	%	5.0	%	N/A		5.0	%	5.0	%	N/A		5.0	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments.

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2013, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on the weighted average of the expected returns on investments based upon the target asset allocation of the pension fund. The Company’s target allocations for the plan’s assets are presented below:



	December 31, 2013
Equity securities	55	%
Fixed income	40	%
Alternative investments	5	%
Total	100	%

The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio of domestic and international equity securities and fixed income securities. The Retirement Plan fund also invests in a real estate limited partnership. The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash and equity risk premium. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads.

FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


•	Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices or securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained from

independent pricing services. These prices are based on observable market data.


•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of the Guaranteed Investment Contract is based on market interest rates of investments

with similar terms and risk characteristics. The Common Collective Trusts are valued using the net asset value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets.


•	Level 3 – Unobservable inputs using data that is not corroborated by market data. The fair value of the real estate limited partnership is reported at the NAV of the investment.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

During 2013, the Company sold the majority of its assets held in active markets, classified as Level 1, and invested these assets in common collective trusts which are classified as Level 2. The fair value of the Company’s Retirement Plan assets at December 31, 2013 and 2012, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	940	$	940	$	—	$	—
Guaranteed Investment Contract	1,126		—		1,126		—
Common Collective Trusts (a)
Equity funds	142,960		—		142,960		—
Fixed income funds	103,948		—		103,948		—
Total Common Collective Trusts	246,908		—		246,908		—
Limited Partnership Interest in Real Estate (b)	8,857		—		—		8,857
Total Plan Investments	$	257,831	$	940	$	248,034	$	8,857



Description of Securities	Fair Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	9,163	$	9,163	$	—	$	—
U.S. Treasury Securities	24,854		24,854		—		—
Guaranteed Investment Contract	1,059		—		1,059		—
Common Stock	52,149		52,149		—		—
Mutual Funds - Fixed Income	59,150		59,150		—		—
Mutual Funds - Equity	65,634		65,634		—		—
Limited Partnership Interest in Real Estate (b)	8,559		—		—		8,559
Total Plan Investments	$	220,568	$	210,950	$	1,059	$	8,559

_____________________


(a)	The Common Collective Trusts are invested in equity or fixed income securities, or a combination thereof. The investment objective of each trust is to produce returns in excess of, or commensurate with, its predefined index.

(b)

This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for commercial development. The Company is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 years. Return on investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land.

The table below reflects the changes in the fair value of investments in real estate during the period (in thousands):



	Fair Value of Investments in Real Estate
Balances at December 31, 2011	$	8,511
Unrealized gain in fair value	48
Balances at December 31, 2012	8,559
Unrealized gain in fair value	298
Balances at December 31, 2013	$	8,857

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2013 and 2012.

The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and Department of Labor ("DOL") regulations.

The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially calculated. The Company expects to contribute $13.9 million to its retirement plans in 2014.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):



	Retirement Income Plan		Non-Qualified Retirement Plans
2014	$	10,902	$	1,870
2015	12,015		1,818
2016	13,180		1,772
2017	14,440		1,829
2018	15,807		1,715
2019-2023	96,510		9,447

In 2014, the Company will implement a redesigned Retirement Income Plan and Excess Benefit Plan. Effective April 1, 2014, the Company will offer a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan will also include an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elect the new cash balance pension plan, the pension benefit earned under the existing final average pay pension plan will be frozen as of March 31, 2014. Employees hired after January 1, 2014 will be automatically enrolled in the cash balance pension plan. The Company anticipates remeasuring the assets and liabilities of the retirement plans during the first quarter of 2014.

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. Annual matching contributions made to the savings plans for the years 2013, 2012 and 2011 were $1.9 million, $1.8 million, and $1.7 million, respectively. Historically, the Company has provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enroll in the cash balance pension plan (discussed above), the Company will provide a 100 percent matching contribution up to 6 percent of the employee's compensation subject to certain other limits and exclusions.

Other Postretirement Benefits

The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are no more than the IRS tax deductible limit, as actuarially calculated. The assets of the plan are primarily invested in common collective trusts which hold equity securities, debt securities, and cash equivalents and are managed by a professional investment manager appointed by the Company.

The Company determined that the prescription drug benefits of its plan were actuarially equivalent to the Medicare Part D benefit provided for in the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. FASB guidance on accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 requires measurement of the postretirement benefit obligation, the plan assets, and the net periodic postretirement benefit cost to

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

reflect the effects of the subsidy. In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the "Acts"). The Company modified the operations of the plan to conform to the effective provisions of the Acts.

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plan (in thousands):



	December 31,
	2013			2012
Change in benefit obligation:
Benefit obligation at end of prior year	$	135,680		$	133,272
Service cost	3,843			4,378
Interest cost	5,156			5,651
Actuarial gain	(48,778		)	(5,009		)
Amendment (a)	(97		)	—
Benefits paid	(4,013		)	(3,929		)
Retiree contributions	1,056			1,086
Medicare Part D subsidy	—			231
Benefit obligation at end of year	92,847			135,680
Change in plan assets:
Fair value of plan assets at end of prior year	36,510			32,817
Actual return on plan assets	5,539			2,605
Employer contribution	3,100			3,700
Benefits paid	(4,013		)	(3,929		)
Retiree contributions	1,056			1,086
Medicare Part D subsidy	—			231
Fair value of plan assets at end of year	42,192			36,510
Funded status (b)	$	(50,655	)	$	(99,170	)

_____________________


(a)	Amendment relates to modification of the Company's Other Postretirement Benefit Plan which limits the Company's premium contribution. The amendment became effective October 3, 2013 and resulted in a remeasurement of the plan.


(b)	These amounts are recognized in the Company’s balance sheets as a non-current liability.

Amounts recognized in accumulated other comprehensive income that have not been recognized as a component of net periodic cost consist of the following (in thousands):



	December 31,
	2013			2012
Net (gain) loss	$	(38,110	)	$	13,630
Prior service credit	(19,210		)	(24,770		)
	$	(57,320	)	$	(11,140	)

The following are the weighted-average actuarial assumptions used to determine the accrued postretirement benefit obligations:



	December 31,
	2013		2012
Discount rate at end of year	4.90	%	4.10	%
Health care cost trend rates:
Initial	7.50	%	7.75	%
Ultimate	4.50	%	4.50	%
Year ultimate reached	2026		2026

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2013 accumulated postretirement benefit obligation by 12.8%. A 1% decrease in the discount rate would increase the December 31, 2013 accumulated postretirement benefit obligation by 16.1%.

Net periodic benefit cost is made up of the components listed below (in thousands):



	Years Ended December 31,
	2013			2012			2011
Service cost	$	3,843		$	4,378		$	2,988
Interest cost	5,156			5,651			5,379
Expected return on plan assets	(1,951		)	(1,714		)	(1,823		)
Amortization of:
Prior service benefit	(5,657		)	(5,877		)	(5,927		)
Net (gain) loss	(626		)	615			(39		)
Net periodic benefit cost	$	765		$	3,053		$	578

The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2013			2012			2011
Net (gain) loss	$	(52,366	)	$	(5,900	)	$	34,517
Prior service benefit	(97		)	—			—
Amortization of:
Prior service benefit	5,657			5,877			5,927
Net gain (loss)	626			(615		)	39
Total recognized in other comprehensive income	$	(46,180	)	$	(638	)	$	40,483

The total recognized in net periodic benefit cost and other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2013			2012		2011
Total recognized in net periodic benefit cost and other comprehensive income	$	(45,415	)	$	2,415	$	41,061

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2014 is a prior service benefit of $4.8 million and a net gain of $2.6 million.

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31:



	2013 (a)		2012		2011
Discount rate at beginning of year	4.1	%	4.3	%	5.5	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.2	%
Health care cost trend rates:
Initial	7.75	%	8.0	%	8.5	%
Ultimate	4.5	%	4.5	%	5.0	%
Year ultimate reached	2026		2026		2018

_____________________

(a) The Other Postretirement Benefits Plan was remeasured at October 3, 2013 due to a plan amendment. The discount rate increased from 4.1% as of January 1, 2013 to 4.9% at the remeasurement date. All other assumptions remained consistent with assumptions used at January 1, 2013.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments.

For measurement purposes, an 7.75% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. The rate was assumed to decrease gradually to 4.5% for 2026 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the December 31, 2013 benefit obligation by $14.3 million or $10.8 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2013 service and interest cost components of the net periodic benefit cost by $2.1 million or $1.2 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.2% effective January 1, 2013. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The Company’s target allocations for the plan’s assets are presented below:



	December 31, 2013
Equity securities	65	%
Fixed income	30	%
Alternative investments	5	%
Total	100	%

The Other Postretirement Benefit Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio of domestic and international equity securities and fixed income securities. The asset portfolio also includes cash equivalents and a real estate limited partnership.The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash and equity risk premium. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads.

FASB guidance on disclosure for other postretirement benefit plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


•	Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices or securities held in the mutual funds and underlying portfolios of the Other Postretirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data.

•

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of municipal securities-tax-exempt are reported at fair value based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. The Common Collective Trusts are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets.


•	Level 3 – Unobservable inputs using data that is not corroborated by market data. The fair value of the real estate limited partnership is reported at the NAV of the investment.

During 2013, the Company sold the majority of its assets held in active markets, classified as Level 1, and invested these assets in common collective trusts which are classified as Level 2. The fair value of the Company’s Other Postretirement Benefits Plan assets at December 31, 2013 and 2012, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



Description of Securities	Fair Value as of December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	33	$	33	$	—	$	—
Common Collective Trusts (a)
Equity funds	28,077		—		28,077		—
Fixed income funds	12,421		—		12,421		—
Total Common Collective Trusts	40,498		—		40,498		—
Limited Partnership Interest in Real Estate (b)	1,661		—		—		1,661
Total Plan Investments	$	42,192	$	33	$	40,498	$	1,661

Description of Securities	Fair Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	2,075	$	2,075	$	—	$	—
Municipal Securities – Tax Exempt	12,811		—		12,811		—
Common Stock	14,397		14,397		—		—
Mutual Funds – Equity	5,622		5,622		—		—
Limited Partnership Interest in Real Estate (b)	1,605		—		—		1,605
Total Plan Investments	$	36,510	$	22,094	$	12,811	$	1,605

___________________


(a)	The Common Collective Trusts are invested in equity or fixed income securities, or a combination thereof. The investment objective of each trust is to produce returns in excess of, or commensurate with, its predefined index.

(b)

This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for commercial development. The Company is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 years. Return of investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land.

The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands):



	Fair Value of Investments in Real Estate
Balance at December 31, 2011	$	1,596
Unrealized gain in fair value	9
Balance at December 31, 2012	1,605
Unrealized gain in fair value	56
Balance at December 31, 2013	$	1,661

There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve month periods ending December 31, 2013 and 2012. There were no purchases, sales, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2013 and 2012.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the ERISA and DOL regulations.

The Company does not expect to contribute to its other postretirement benefits plan in 2014. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):



2014	$	3,024
2015	3,414
2016	3,810
2017	4,230
2018	4,639
2019-2023	28,238

Annual Short-Term Incentive Plan

The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on safety, regulatory compliance, and customer satisfaction. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan. In 2013, the Company reached the required levels of earnings per share, safety, regulatory compliance, and customer satisfaction goals for an incentive payment of $4.0 million. The Company reached the required levels of earnings per share, safety, and regulatory compliance goals for an incentive payment of $7.9 million and $7.3 million in 2012 and 2011, respectively. The Company has renewed the Incentive Plan in 2014 with similar goals.

N. Franchises and Significant Customers

El Paso and Las Cruces Franchises

The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below:



City	Period	Franchise Fee	(a)
El Paso	August 1, 2010 - Present	4.00%	(b)
Las Cruces	February 1, 2000 - Present	2.00%

_________________

(a) Based on a percentage of revenue.

(b) 0.75% of the El Paso franchise fee is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.

Military Installations

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

O. Financial Instruments and Investments

FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds, long-term debt, short-term borrowings under the RCF, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning trust funds are carried at fair value.

Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short-term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):



	December 31,
	2013				2012
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	193,990	$	193,135	$	215,228
Senior Notes	696,485		734,515		696,400		823,497
RGRT Senior Notes (1)	110,000		115,850		110,000		120,985
RCF (1)	14,352		14,352		22,155		22,155
Total	$	1,013,972	$	1,058,707	$	1,021,690	$	1,181,865

__________________

(1)

Nuclear fuel financing as of December 31, 2013 and December 31, 2012 is funded through the $110 million RGRT Senior Notes and $14.4 million and $22.2 million, respectively under the RCF. As of December 31, 2013 and 2012, no amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value.

Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6% Senior Notes. In 2014, approximately $0.4 million of this accumulated other comprehensive loss item will be reclassified to interest expense.

Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2013, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases and normal sales" exception provided in FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.

The Company determined that certain of its natural gas commodity contracts with optionality features are not eligible for the normal purchases exception and, therefore, are required to be accounted for as derivative instruments pursuant to FASB guidance for accounting for derivative instruments and hedging activities. However, as of December 31, 2013, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $214.1 million and $187.1 million at December 31, 2013 and 2012, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



	December 31, 2013
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	6,444	$	(169	)	$	1,421	$	(119	)	$	7,865	$	(288	)
U.S. Government Bonds	8,114		(245		)	10,866		(840		)	18,980		(1,085		)
Municipal Obligations	12,286		(335		)	7,782		(479		)	20,068		(814		)
Corporate Obligations	3,284		(96		)	901		(54		)	4,185		(150		)
Total Debt Securities	30,128		(845		)	20,970		(1,492		)	51,098		(2,337		)
Common Stock	2,305		(126		)	—		—			2,305		(126		)
Total Temporarily Impaired Securities	$	32,433	$	(971	)	$	20,970	$	(1,492	)	$	53,403	$	(2,463	)

____________________


(1)	Includes approximately 122 securities.



	December 31, 2012
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities	$	1,792	$	(5	)	$	416	$	(9	)	$	2,208	$	(14	)
U.S. Government Bonds	6,633		(79		)	4,457		(114		)	11,090		(193		)
Municipal Obligations	5,306		(39		)	5,760		(241		)	11,066		(280		)
Corporate Obligations	452		(11		)	—		—			452		(11		)
Total Debt Securities	14,183		(134		)	10,633		(364		)	24,816		(498		)
Common stock	3,603		(409		)	—		—			3,603		(409		)
Total Temporarily Impaired Securities	$	17,786	$	(543	)	$	10,633	$	(364	)	$	28,419	$	(907	)

______________________


(2)	Includes approximately 65 securities.

The Company monitors the length of time the security trades below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these securities until their market price recovers, these securities are considered temporarily impaired. The Company does not anticipate expending monies held in trust before 2044 or a later period when the Company begins to decommission Palo Verde.

The reported fair values also include gross unrealized gains on marketable securities which have not been recognized in the Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands):

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



	December 31, 2013				December 31, 2012
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	9,929	$	433	$	17,289	$	1,036
U.S. Government Bonds	6,258		126		13,295		678
Municipal Obligations	8,783		450		22,797		1,531
Corporate Obligations	9,188		506		12,378		1,134
Total Debt Securities	34,158		1,515		65,759		4,379
Common Stock	103,808		43,145		73,210		22,839
Equity Mutual Funds	16,802		3,081		15,194		1,821
Cash and Cash Equivalents	5,924		—		4,471		—
Total	$	160,692	$	47,741	$	158,634	$	29,039

The Company’s marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company’s mortgage-backed securities, based on contractual maturity, are due in ten years or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from three years to eight years and reflects anticipated future prepayments. The contractual year for maturity for these available-for-sale securities as of December 31, 2013 is as follows (in thousands):



	Total		2014		2015 through 2018		2019 through 2023		2024 and Beyond
Municipal Debt Obligations	$	28,851	$	1,486	$	13,311	$	10,920	$	3,134
Corporate Debt Obligations	13,373		321		3,711		5,525		3,816
U.S. Government Bonds	25,238		1,216		14,149		7,217		2,656

The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. For the twelve months ended December 31, 2013, 2012, and 2011 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):



	2013		2012			2011
Unrealized holding losses included in pre-tax income	$	—	$	(479	)	$	(2,116	)

The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses the specific identification basis to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2013, 2012, and 2011 and the related effects on pre-tax income are as follows (in thousands):



	2013			2012			2011
Proceeds from sales or maturities of available-for-sale securities	$	56,148		$	98,542		$	82,926
Gross realized gains included in pre-tax income	$	986		$	1,478		$	1,479
Gross realized losses included in pre-tax income	(433		)	(2,041		)	(721		)
Gross unrealized losses included in pre-tax income	—			(479		)	(2,116		)
Net gains (losses) in pre-tax income	$	553		$	(1,042	)	$	(1,358	)
Net unrealized holding gains included in accumulated other comprehensive income	$	17,699		$	9,927		$	1,570
Net (gains) losses reclassified out of accumulated other comprehensive income	(553		)	1,042			1,358
Net gains in other comprehensive income	$	17,146		$	10,969		$	2,928

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Fair Value Measurements. FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on the balance sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


•	Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market.

•

Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.


•	Level 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analyses. Financial assets utilizing Level 3 inputs include the Company's investments in debt securities.

The securities in the Company’s decommissioning trust funds are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. FASB guidance identifies this valuation technique as the "market approach" with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other than temporary.

The fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2013 and 2012, and the level within the three levels of the fair value hierarchy defined by FASB guidance are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,555	$	—	$	—	$	1,555
Available for sale:
U.S. Government Bonds	$	25,238	$	25,238	$	—	$	—
Federal Agency Mortgage Backed Securities	17,794		—		17,794		—
Municipal Obligations	28,851		—		28,851		—
Corporate Obligations	13,373		—		13,373		—
Subtotal, Debt Securities	85,256		25,238		60,018		—
Common Stock	106,113		106,113		—		—
Equity Mutual Funds	16,802		16,802		—		—
Cash and Cash Equivalents	5,924		5,924		—		—
Total available for sale	$	214,095	$	154,077	$	60,018	$	—

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



Description of Securities	Fair Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,295	$	—	$	—	$	1,295
Available for sale:
U.S. Government Bonds	$	24,385	$	24,385	$	—	$	—
Federal Agency Mortgage Backed Securities	19,497		—		19,497		—
Municipal Obligations	33,863		—		33,863		—
Corporate Obligations	12,830		—		12,830		—
Subtotal, Debt Securities	90,575		24,385		66,190		—
Common Stock	76,813		76,813		—		—
Equity Mutual Funds	15,194		15,194		—		—
Cash and Cash Equivalents	4,471		4,471		—		—
Total available for sale	$	187,053	$	120,863	$	66,190	$	—

Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands):



	2013		2012
Balance at January 1	$	1,295	$	1,120
Net unrealized gains in fair value recognized in income (a)	260		175
Balance at December 31	$	1,555	$	1,295

_____________________

(a) These amounts are reflected in the Company's statement of operations as investment and interest income.

P. Supplemental Statements of Cash Flows Disclosures



	Years Ended December 31,
	2013		2012		2011
	(In thousands)
Cash paid (received) for:
Interest on long-term debt and borrowing under the revolving credit facility	$	53,752	$	50,189	$	48,797
Income taxes paid (refund), net	244		5,031		(6,260		)
Non-cash financing activities:
Grants of restricted shares of common stock	3,224		2,411		3,268
Issuance of performance shares	849		1,193		628
Acquisition of treasury stock for options exercised	—		—		500

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Q. Selected Quarterly Financial Data (Unaudited)

The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.



	2013 Quarters								2012 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	190,297	$	282,661	$	240,114	$	177,290	$	188,802	$	267,249	$	228,252	$	168,578
Operating income	6,050		85,896		54,344		19,345		13,708		86,396		56,512		12,042
Net income	1,191		50,565		29,193		7,634		4,819		51,789		30,894		3,344
Basic earnings per share:
Net income	0.03		1.26		0.73		0.19		0.12		1.29		0.77		0.08
Diluted earnings per share:
Net income	0.03		1.26		0.72		0.19		0.12		1.29		0.77		0.08
Dividends declared per share of common stock	0.265		0.265		0.265		0.25		0.25		0.25		0.25		0.22

________________


(1)	Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.

Table of Contents


Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.


Item 9A.	Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2013, our disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control Over Financial Reporting. Management’s Annual Report on Internal Control over Financial Reporting is included herein under the caption "Management Report on Internal Control Over Financial Reporting" on page 43 of this report.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2013, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.


Item 9B.	Other Information

None.

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PART III


Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance

Information regarding directors is incorporated herein by reference from our definitive proxy statement for the 2014 Annual Meeting of Shareholders (the "2014 Proxy Statement") under the heading "Nominees and Directors of the Company." Information regarding executive officers, included herein under the caption "Executive Officers of the Registrant" in Part I, Item 1 above, is incorporated herein by reference.

The information concerning the identification of our standing audit committee required by this Item is incorporated by reference from the 2014 Proxy Statement under the caption "Committees" under the heading "Directors’ Meetings, Compensation and Committees," and under the heading "Audit Committee Report."

The information concerning our audit committee financial experts required by this Item is incorporated by reference from the 2014 Proxy Statement under the caption "Committees" under the heading "Directors’ Meetings, Compensation and Committees."

The information concerning compliance with Section 16(a) of the Exchange Act required by this Item is incorporated by reference from the 2014 Proxy Statement under the heading "Section 16(a) Beneficial Ownership Reporting Compliance."

We have adopted a Code of Ethics that is incorporated by reference from the 2014 Proxy Statement under the caption "Business Conduct Policies" under the heading "Corporate Governance."


Item 11.	Executive Compensation

Incorporated herein by reference from the 2014 Proxy Statement under the heading "Summary of Compensation."


Item 12.	Security Ownership of Certain Beneficial Management

Incorporated herein by reference from the 2014 Proxy Statement under the heading "Security Ownership of Certain Beneficial Owners and Management."

Equity Compensation Plan Information



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans
approved by security holders	—	$	—	490,362
Equity compensation plans
not approved by security holders	—	—		—
Total	—	$	—	490,362


Item 13.	Certain Relationships and Related Transactions, and Director Independence

Incorporated herein by reference from the 2014 Proxy Statement under the heading "Certain Relationships and Related Party Transactions."


Item 14.	Principal Accounting Fees and Services

Incorporated herein by reference from the 2014 Proxy Statement under the heading "Independent Registered Public Accounting Firm."

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PART IV


Item 15.	Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report:



		Page
1.	Financial Statements:

	See Index to Financial Statements	44

2.	Financial Statement Schedules:

	All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.

3.	Exhibits

Certain of the following documents are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission, and, pursuant to Rule 12b-32 and Regulation 201.24, are incorporated herein by reference.

Table of Contents



Exhibit Number		Title
Exhibit 3 – Articles of Incorporation and Bylaws:
	3.01	–	Restated Articles of Incorporation of the Company, dated February 7, 1996 and effective February 12, 1996. (Exhibit 3.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	3.02	–	Bylaws of the Company, dated February 6, 1996. (Exhibit 3.02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
Exhibit 4 – Instruments Defining the Rights of Security Holders, including Indentures:
	4.01	–	General Mortgage Indenture and Deed of Trust, dated as of February 1, 1996, and First Supplemental Indenture, dated as of February 1, 1996, including form of Series A through H First Mortgage Bonds. (Exhibit 4.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.01-01		–	Second Supplemental Indenture, dated as of August 19, 1997, to Exhibit 4.01. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1997)
4.01-02		–	Fifth Supplemental Indenture, dated as of December 17, 2004, to Exhibit 4.01. (Exhibit 4.01-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004)
4.01-03		–	Sixth Supplemental Indenture to Exhibit 4.01, dated as of May 5, 2005 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
	4.02	–	Bond Purchase Agreement dated March 19, 2009, among El Paso Electric Company, J.P. Morgan Securities, Inc., BNY Mellon Capital Markets, LLC, Maricopa County, Arizona Pollution Control Corporation, relating to the Pollution Control Bonds referred to in Exhibit 4.06 and 4.08. (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.03	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank of California, N.A. as Trustee dated as of August 1, 2012 relating to $59,235,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2012 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.04	–	Loan Agreement dated August 1, 2012 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.05	–	Reserved
	4.06	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $63,500,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.07	–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.06. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.08	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $37,100,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series B (El Paso Electric Company Palo Verde Project). (Exhibit 4.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.09	–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.08. (Exhibit 4.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.10	–	Remarketing and Purchase Agreement dated August 1, 2012 among El Paso Electric Company and U.S. Bancorp Investments, Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.13. (Exhibit 4.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.11	–	Tender Agreement dated August 1, 2012 between El Paso Electric Company and Union Bank, N.A., relating to the Pollution Control Bonds referred to in Exhibit 4.13. (Exhibit 4.03 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)

100

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Exhibit Number		Title
	4.12	–	Amended and Restated Installment Sale Agreement, dated as of August 1, 2012, between El Paso Electric Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.13. (Exhibit 4.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.13	–	Ordinance No. 2012-1256 adopted by the City Council of Farmington, New Mexico on June 12, 2012 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 in aggregate principal amount of its Pollution Control Revenue Refunding Bonds, 2012 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.01 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.14	–	Debt Securities Indenture, dated as of May 1, 2005. (Exhibit 4.1 to the Company's Current Report on Form 8-K, dated May 17, 2005)
	4.15	–	First Supplemental Indenture, dated as of May 19, 2008. (Exhibit 4.4 to the Company's Registration Statement on Form S-3, dated May 20, 2008)
	4.16	–	Securities Resolution No. 1, dated May 11, 2005, relating to the Company's 6.00% Senior Notes due 2035. (Exhibit 4.2 to the Company's Current Report on Form 8-K dated May 17, 2005)
	4.17	–	Securities Resolution No. 2, dated May 29, 2008, relating to the Company's 7.50% Senior Notes due 2038. (Exhibit 4.2 to the Company's Current Report on Form 8-K dated June 3, 2008)
	4.18	–	Securities Resolution No. 3, dated December 3, 2012, relating to the Company's 3.30% Senior Notes due 2022. (Exhibit 4.01 to the Company's Current Report on Form 8-K dated December 6, 2012)
	4.19	–	Bond Purchase Agreement dated August 15, 2012, among Maricopa County, Arizona Pollution Control Corporation, U.S. Bancorp Investments, Inc., and Merrill Lynch, Pierce, Fenner & Smith Incorporated, relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
Exhibit 10 – Material Contracts:
	10.01	–	Co-Tenancy Agreement, dated July 19, 1966, and Amendments No. 1 through 5 thereto, between the Participants of the Four Corners Project, defining the respective ownerships, rights and obligations of the Parties. (Exhibit 10.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.01-01		–	Amendment No. 6, dated February 3, 2000, to Exhibit 10.01. (Exhibit 10.01-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
	10.02	–	Supplemental and Additional Indenture of Lease, dated May 27, 1966, including amendments and supplements to original Lease Four Corners Units 1, 2 and 3, between the Navajo Tribe of Indians and Arizona Public Service Company, and including new Lease Four Corners Units 4 and 5, between the Navajo Tribe of Indians and Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company. (Exhibit 4-e to Registration Statement No. 2-28692 on Form S-9)
10.02-01		–	Amendment and Supplement No. 1, dated March 21, 1985, to Exhibit 10.02. (Exhibit 19.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1985)
	10.03	–	El Paso Electric Company 1996 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-17971 on Form S-8)
	10.04	–	Four Corners Project Operating Agreement, dated May 15, 1969, between Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company, and Amendments 1 through 10 thereto. (Exhibit 10.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.04-01		–	Amendment No. 11, dated May 23, 1997, to Exhibit 10.04. (Exhibit 10.04-01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997)
10.04-02		–	Amendment No. 12, dated February 3, 2000, to Exhibit 10.04. (Exhibit 10.04-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

101

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Exhibit Number		Title
	10.05	–	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties, and Amendments No. 1 through 13 thereto. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.05-01		–	Amendment No. 14, dated June 20, 2000, to Exhibit 10.05. (Exhibit 10.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.05-02		–	Amendment No. 15, dated January 13, 2011, to the Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company (Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	10.06	–	ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.07	–	Arizona Nuclear Power Project High Voltage Switchyard Participation Agreement, dated August 20, 1981. APS Contract No. 2252-419.00. (Exhibit 20.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1981)
10.07-01		–	Amendment No. 1, dated November 20, 1986, to Exhibit 10.07. (Exhibit 10.11-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
	10.08	–	Firm Palo Verde Nuclear Generating Station Transmission Service Agreement, between Salt River Project Agricultural Improvement and Power District and the Company, dated October 18, 1983. (Exhibit 19.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1983)
	10.09	–	Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A through F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.10	–	Amrad to Artesia 345 KV Transmission System and DC Terminal Participation Agreement, dated December 8, 1981, between the Company and Texas-New Mexico Power Company, and the First through Third Supplemental Agreements thereto. (Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
#10.11		–	El Paso Electric Company Excess Benefit Plan, dated as of December 31, 2008. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	10.12	–	Interconnection Agreement and Amendment No. 1, dated July 19, 1966, between the Company and Public Service Company of New Mexico. (Exhibit 19.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
	10.13	–	Southwest New Mexico Transmission Project Participation Agreement, dated April 11, 1977, between Public Service Company of New Mexico, Community Public Service Company and the Company, and Amendments 1 through 5 thereto. (Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.13-01		–	Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.13. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
	10.14	–	Tucson-El Paso Power Exchange and Transmission Agreement, dated April 19, 1982, between Tucson Electric Power Company and the Company. (Exhibit 19.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
10.14-01		–	Settlement Agreement between TEP and the Company, dated April 26, 2011, to Exhibit 10.14. (Exhibit 10.14-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011)
	10.15	–	Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
	10.16	–	Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)

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Exhibit Number		Title
#10.17		–	Form of Indemnity Agreement, between the Company and its directors and officers. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012)
	10.18	–	Interchange Agreement, executed April 14, 1982, between Comisión Federal de Electricidad and the Company. (Exhibit 19.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1991)
	10.19	–	Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.20	–	Purchase Contract, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.20-01		–	Second Amendment, dated as of July 12, 2007, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007)
10.20-02		–	Third Amendment, dated as of August 17, 2010, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.20-03		–	Fourth Amendment, dated as of September 23, 2010, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
	10.21	–	Note Purchase Agreement, dated as of August 17, 2010, between El Paso Electric Company, Rio Grande Resources Trust II and the purchasers named therein. (Exhibit 10.1 to the Company’s Form 8-K, dated as of August 17, 2010)
	10.22	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 1. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.23	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 2. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.24	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 3. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.25	–	Credit agreement dated as of September 23, 2010, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank, N.A., as syndication agent. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.25-01		–	Amended and Restated Credit Agreement dated as of November 15, 2011, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders party thereto, JP Morgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank, N.A., as syndication agent.(Exhibit 10.25-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011)
10.25-02		–	Incremental Facility Assumption Agreement dated as of March 29, 2012, related to the Amended and Restated Credit Agreement, referred to in Exhibit 10.25-01, among the Company and The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as issuing bank and as administrative agent and Union Bank, N.A., as syndication agent. (Exhibit 10.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012)
*10.25-03		–	Second Amended and Restated Credit agreement dated as of January 14, 2014, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II, the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank of California, N.A., as syndication agent.
†10.26		–	Amended and Restated Change in Control Agreement between the Company and certain key officers of the Company. (Exhibit 9.1 to the Company’s Form 8-K as of March 20, 2007)
	10.27	–	Reserved
††10.28		–	Form of Stock Option Agreement between the Company and certain key officers of the Company. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)

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Exhibit Number		Title
†††10.29		–	Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.30		–	Reserved
#10.31		–	El Paso Electric Company 1999 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-82129 on Form S-8)
	10.32	–	Settlement Agreement, dated as of February 24, 2000, with the City of Las Cruces. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
	10.33	–	Franchise Agreement, dated April 3, 2000, between the Company and the City of Las Cruces. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
#10.34		–	Employment Agreement for Hector Puente, dated April 23, 2001. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001)
	10.35	–	Shiprock – Four Corners Project 345 kV Switchyard Interconnection Agreement, dated March 6, 2002. APS Contract No. 51999. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002)
	10.36	–	Interconnection Agreement dated as of May 23, 2002, between the Company and the Public Service Company of New Mexico. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
10.36-01		–	First Amended and Restated Interconnection Agreement, dated October 9, 2003, to Exhibit 10.36. (Exhibit 10.52.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003)
	10.37	–	Reserved
	10.38	–	Reserved
	10.39	–	Eight Treasury Rate Lock agreements between the Company and Credit Suisse First Boston International. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
††††10.40		–	Master Power Purchase and Sale Agreement and Transaction Agreement, dated as of July 7, 2004, between the Company and Southwestern Public Service Company. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
	10.41	–	Reserved
	10.42	–	Power Purchase and Sale Agreement, dated as of December 16, 2005, between the Company and Phelps Dodge Energy Services, LLC. (Exhibit 10.42 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005)
10.42-01		–	Letter Agreement, dated June 3, 2008, to Exhibit 10.42. (Exhibit 10.42-01 to the Company's Annual Report on Form 10-k for the year ended December 31, 2010)
10.42-02		–	Letter Agreement, dated November 26, 2008, to Exhibit 10.42. (Exhibit 10.42-02 to the Company's Annual Report on Form 10-k for the year ended December 31, 2010)
10.42-03		–	Letter Agreement, dated November 12, 2010, to Exhibit 10.42. (Exhibit 10.42-03 to the Company's Annual Report on Form 10-k for the year ended December 31, 2010)
10.42-04		–	Letter Agreement, dated April 29, 2011, to Exhibit 10.42. (Exhibit 10.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011)
	10.43	–	Settlement Agreement between the State of Texas and the Company, dated as of October 17, 2006. (Exhibit 10.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006)
††††10.44		–	Confirmation of Power Purchase Transaction, dated April 18, 2007, between the Company and Credit Suisse Energy LLC. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007)
††††10.44-01		–	Amended Confirmation of Power Purchase Transaction, dated September 3, 2008, between the Company and Credit Suisse Energy LLC. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008)
††††10.44-02		–	Amended Confirmation of Power Purchase Transaction, dated March 30, 2009, between the Company and Credit Suisse Energy LLC. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
††††10.45		–	Confirmation of Power Sales Transaction, dated April 18, 2007, between the Company and Imperial Irrigation District. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007)

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Exhibit Number		Title
††††10.45-01		–	Amended Confirmation of Power Sales Transaction, dated August 29, 2008, between the Company and Imperial Irrigation District. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008)
††††10.45-02		–	Amended Confirmation of Power Sales Transaction, dated March 31, 2009, between the Company and Imperial Irrigation District. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
#10.46		–	El Paso Electric Company 2007 Long-Term Incentive Plan. (Exhibit 10.1 to the Company’s Form 8-K, dated as of May 2, 2007)
#10.47		–	Employment Agreement between the Company and Thomas V. Shockley, III, dated June 1, 2012. (Exhibit 10.05 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012)
#10.47-01		–	Amendment to Employment Agreement between the Company and Thomas V. Shockley, III dated May 2, 2013. (Exhibit No. 1 to the Company's Form 8-K, dated May 2, 2013.)
*#10.47-02		–	Amended and Restated Employment Agreement between the Company and Thomas V. Shockley, III, dated November 20, 2013.
*10.48		–	Employment Transition Agreement between the Company and David G. Carpenter, dated November 20, 2013.
*10.49		–	Employment Transition Agreement between the Company and Hector R. Puente, dated November 20, 2013.
Exhibit 12 – Computation of Ratios:
*12.01		–	Computation of Ratios of Earnings to Fixed Charges
Exhibit 23 – Consent of Experts:
*23.01		–	Consent of KPMG LLP (set forth on page 109 of this report)
Exhibit 24 – Power of Attorney:
*24.01		–	Power of Attorney (set forth on page 107 of the Original Form 10-K)
*24.02		–	Certified copy of resolution authorizing signatures pursuant to Power of Attorney
Exhibit 31 and 32 – Certifications:
*31.01		–	Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.01		–	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99 – Additional Exhibits:
	99.01	–	Agreed Order, entered August 30, 1995, by the Public Utility Commission of Texas. (Exhibit 99.31 to Registration Statement No. 33-99744 on Form S-1)
	99.02	–	Reserved
	99.03	–	Final Order, entered September 24, 1998, by the New Mexico Public Utility Commission. (Exhibit 99.31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
	99.04	–	Final Order, entered June 8, 1999, by the Public Utility Commission of Texas. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
	99.05	–	Final Order, entered January 8, 2002, by the New Mexico Public Utility Commission. (Exhibit 99.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
	99.06	–	News Release, dated as of December 5, 2002, by the El Paso Electric Company announcing settlement with the FERC Trial Staff. (Exhibit 99.01 to the Company’s Form 8-K, dated as of December 6, 2002)
	99.07	–	"Stipulated Facts and Remedies," dated as of December 5, 2002, to be filed by the FERC Trial Staff as part of its written testimony. (Exhibit 99.02 to the Company’s Form 8-K, dated as of December 6, 2002)
Exhibit 101 – XBRL – Related Documents:
*101.INS		–	XBRL Instance Linkbase Document
*101.SCH		–	XBRL Taxonomy Extension Schema Linkbase Document
*101.CAL		–	XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		–	XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		–	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		–	XBRL Taxonomy Extension Presentation Linkbase Document

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	*			Filed herewith.
	#			Management contracts or compensatory plans or arrangements required to be identified by Item 15(a)(3) of Form 10-K.
	†			Twelve agreements, substantially identical in all material respects to this exhibit, have been entered into with David G. Carpenter; Steven P. Busser; Steven T. Buraczyk; Robert C. Doyle; Nathan T. Hirschi; Mary E. Kipp; Kerry B. Lore; Rocky R. Miracle; Hector R. Puente; Andres R. Ramirez; Henry Wayne Soza; and Guillermo Silva, Jr., officers of the Company.
	††			One agreement, dated as of December 4, 2003, identical in all material respects to this Exhibit, has been entered into with Steven P. Busser; officer of the Company.
	†††			In lieu of non-employee director cash compensation, nine agreements, dated as of January 1, 2012, April 1, 2012, and July 1, 2012, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Patricia Z. Holland-Branch, and Stephen N. Wertheimer; directors of the Company.
				In lieu of non-employee director cash compensation, ten agreements, dated as of May 31, 2012, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland‑Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
				In lieu of non-employee director cash compensation, four agreements, dated as of October 1, 2012, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Patricia Z. Holland‑Branch; Michael K. Parks; and Stephen N. Wertheimer; directors of the Company.
				In lieu of non-employee director cash compensation, eleven agreements, dated as of May 9, 2013, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; Edward Escudero, James W. Harris; Woodley L. Hunt; Patricia Z. Holland‑Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
				In lieu of non-employee director cash compensation, eight agreements, dated as of January 1, 2013 and April 1, 2013, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Patricia Z. Holland-Branch, Michael K. Parks; and Stephen N. Wertheimer; directors of the Company.
				In lieu of non-employee director cash compensation, twelve agreements, dated as of July 1, 2013 and October 1, 2013, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Edward Escudero, Patricia Z. Holland-Branch, Woodley L. Hunt, Michael K. Parks; and Stephen N. Wertheimer; directors of the Company.
	††††			Confidential treatment has been requested and received for the redacted portions of these Exhibits. The copies filed omit the information subject to the confidentiality request. Omissions are designated as "****." A complete version of these Exhibits has been filed separately with the Securities and Exchange Commission.

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of El Paso Electric Company, a Texas corporation, and the undersigned directors and officers of El Paso Electric Company, hereby constitutes and appoints Thomas V. Shockley III, Nathan T. Hirschi and Mary E. Kipp, its, his or her true and lawful attorneys-in-fact and agents, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power to act alone, to sign this report and any and all amendments to this report, and to file each such amendment to this report, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as it, he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of February 2014.



EL PASO ELECTRIC COMPANY

By:	/s/ THOMAS V. SHOCKLEY III
	Thomas V. Shockley III
	Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.



Signature	Title	Date

/s/ THOMAS V. SHOCKLEY III	Chief Executive Officer (Principal Executive Officer)	February 26, 2014
(Thomas V. Shockley III)	Chief Executive Officer (Principal Executive Officer)

/s/ NATHAN T. HIRSCHI	Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer )	February 26, 2014
(Nathan T. Hirschi)

/s/ CATHERINE A. ALLEN	Director	February 26, 2014
(Catherine A. Allen)

/s/ JOHN ROBERT BROWN	Director	February 26, 2014
(John Robert Brown)

/s/ JAMES W. CICCONI	Director	February 26, 2014
(James W. Cicconi)

/s/ EDWARD ESCUDERO	Director	February 26, 2014
(Edward Escudero)

/s/ JAMES W. HARRIS	Director	February 26, 2014
(James W. Harris)

/s/ PATRICIA Z. HOLLAND-BRANCH	Director	February 26, 2014
(Patricia Z. Holland-Branch)

/s/ WOODLEY L. HUNT	Director	February 26, 2014
(Woodley L. Hunt)

/s/ MICHAEL K. PARKS	Director	February 26, 2014
(Michael K. Parks)

/s/ ERIC B. SIEGEL	Director	February 26, 2014
(Eric B. Siegel)

/s/ STEPHEN N. WERTHEIMER	Director	February 26, 2014
(Stephen N. Wertheimer)

/s/ CHARLES A. YAMARONE	Director	February 26, 2014
(Charles A. Yamarone)

108